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HomeMy WebLinkAboutSummary Progress Report Cordova Power Supply Feasibility Analysis, March 22, 1982o, ~ A Bs Gree oY mata a Os eee LE PROPERTY OF: Alaska Power: Authority’ 334 W. 5th Ave. Anchorage, Alaska 99501... SUMMARY PROGRESS REPORT CORDOVA POWER SUPPLY FEASIBILITY ANALYSIS MARCH 22, 1982 AX Stone & Webster Engineering Corporation ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION DENVER OPERATIONS CENTER A GREENWOOD PLAZA, DENVER, COLORADO ADDRESS ALL CORRESPONDENCE TO P.O. BOX 5406, DENVER, COLORADO 80217 BOSTON DESIGN NEW YORK CONSTRUCTION CHERRY HILL, N.J REPORTS DENVER EXAMINATIONS CHICAGO CONSULTING HOUSTON ENGINEERING PORTLAND, OREGON SAN DIEGO WASHINGTON, D.C. Eric P. Yould March 22, 1982 Executive Director Alaska Power Authority J.O. No. 14101.08 334 West 5th Avenue Letter No. SWEC/APA-08 Anchorage, Alaska 99501 Attention: Mr. Eric Marchegiani Project Manager RECEIVED Dear Mr. Marchegiani: MAA 34 $982 SUMMARY PROGRESS REPORT ALASKA POWER AUTHORITY CORDOVA FEASIBILITY STUDY - PHASE I This interim report is submitted as part of the Cordova Power Supply Feasibility Analysis and provides a summary of study progress through March 10, 1982. During this study phase, an in-depth assessment and comparison is being made of those diesel, coal, hydroelectric and intertie alternatives (individually and in combination) considered potentially feasible solutions for Cordova's energy needs. Competitive alternatives will then be used to formulate energy supply plans which minimize both electrical power costs and adverse environmental and social impacts. Evaluation of these alternatives will result in selection of a single preferred plan for development and optimization during Phase II. The scope of this study has recently been modified to include investigation of several additional alternatives and extension of Phase I completion to June 1982. Therefore, this report provides a summary of analyses of nineteen separate alternatives which have been pursued for varying periods of time and with differing levels of effort. The resultant descriptions of effort and status are neither uniform nor complete. However, technical analyses and cost estimates have been completed for all alternatives (except newly added interties) in sufficient detail and reliability to permit comparisons and initial decisions on competitiveness. It is now apparent that diesel and coal-fired generation alternatives are not competitive with hydroelectric or purchased power. Therefore, we recommend that only the Existing Diesel Plant (D001), be developed further to provide a base case comparison for other more competitive alternatives. Continued effort related to other coal and diesel power plans should now be ended and study resources applied to more competitive alternatives. APA March 22, 1982 Page Two In the case of hydroelectric alternatives, development of Power Creek is considered an unacceptable technical risk, and capital costs for Allison Lake are excessive when compared with Silver Lake. It is therefore recommended that further hydroelectric investigations be limited to Silver Lake as a primary candidate for power supply, and Crater Lake and other small hydroelectric sites as supplemental power sources. Finally, analysis of transmission line costs indicates that the Copper River Route from Cordova to Solomon Gulch and the Cordova to Whittier Submarine Cable are not cost competitive with other transmission lines, and further investigation is not warranted. In summary, we now recommend that continued investigation be limited to the following seven alternatives. DO1l DIESEL BASE CASE HO2 SILVER LAKE HYDROELECTRIC HO5 HYDROELECTRIC SITES WITH LESS THAN 3 MW CAPACITY TOL CORDOVA TO SOLOMON GULCH INTERTIE - COASTAL ROUTE TO2 CORDOVA TO SOLOMON GULCH INTERTIE WITH TAP TO SILVER LAKE TO5 CORDOVA TO SOLOMON GULCH INTERTIE - SUBMARINE CABLE TO6 TEELAND-PALMER-GLENNALLEN INTERTIE One final recommendation is warranted. At this stage of investigation, the Silver Lake hydroelectric option appears to be very competitive. However, were it to be selected as the preferred plan for Cordova, further development and optimization would be hampered by a lack of field data. Therefore, we believe it would be cost effective to begin stream flow data collection prior to completion of Phase I. This would save perhaps as much as one year in total time required if Silver Lake is finally selected as part of the preferred power supply plan for Cordova. We trust the enclosed report meets your requirements, and that you concur in the recommendations noted above. Should you have any questions concerning this report or require clarification or additional information, do not hesitate to contact us. Very truly yours, N. K. Whitcomb Project Manager BJR/NKW/jam CC: DOWL Engineers - M. R. Nichols Dryden & LaRue - D. S. LaRue LEMCO Engineers - M. Cheek Green Construction - D. Argetsinger STONE & WEBSTER A CORDOVA POWER SUPPLY FEASIBILITY ANALYSIS PHASE I SUMMARY PROGRESS REPORT March 22, 1982 STONE & WEBSTER A PREFACE The scope of this study has recently been modified to include investigation of several additional alternatives and extension of Phase I completion to June 1982. Therefore, this report provides a summary of analyses of nineteen separate alternatives which have been pursued for varying periods of time and with differing levels of effort. The resultant descriptions of effort and status are neither uniform nor complete. However, technical analyses and cost estimates have been completed for all alternatives (except newly added interties) in sufficient detail and reliability to permit comparisons and initial decisions on competitiveness. STONE & WEBSTER A 1. 2. Mh hw ~w . FWhHFH . . ONIaNUFWNHe- W101 010101 . CORDOVA FEASIBILITY STUDY PHASE I SUMMARY PROGRESS REPORT Table of Contents SECTION EXECUTIVE SUMMARY* INTRODUCTION Study Purpose Assumptions and Constraints* Study Methodology Alternatives Investigated CURRENT DIESEL GENERATION* ELECTRICAL ENERGY FORECASTS Cordova Annual and Peak Demands Regional Availability and Demands Selected Evaluation Parameters OPTIMIZED DIESEL GENERATION Methodology, Parameters Technical Analysis and System Description Environmental and Socioeconomic Issues Siting, Conceptual Design and Capital Cost Fuel Supply Costs Maintenance and Operation* Economic Analysis Back-Up Diesel Plant ii PAGE VUIW PD oon 10 10 10 10 11 23 13 13 14 STONE & WEBSTER A Table of Contents (cont) SECTION 6. COAL GENERATION Methodology, Parameters Katalla (C05) Cordova-Land Options (C01, C03, C04) Cordova-Barge Option (C02) Optimized Coal Generation OO OVO" OV . WI FwWhy 7. HYDROELECTRIC GENERATION Methodology, Parameters Power Creek (HO1) Silver Lake (H02) Allison Lake (HO3) Other Sites (HO4) ANAAN eee UEWN Fe ee 8. TRANSMISSION Methodology, Paramaters Copper River Route (T03) Coastal Route (TO1) Katalla Route (TO4) Palmer-Glennallen Route (T06) Submarine Routes (T05 & 107) Co © © O@ .e AN FWh Fr 9. ECONOMICS* 10. COMPARISON OF ALTERNATIVES* 11. RECOMMENDATIONS 11.1 Selected Alternative(s) 11.2 Phase II Activities* *To be provided in Final Phase I Report iii PAGE Pe a9 15 16 23 24 28 28 33 39 43 46 50 50 53 56 57 59 61 64 65 66 66 67 STONE & WEBSTER A 1. EXECUTIVE SUMMARY (To be provided in the Final Phase I Report) STONE & WEBSTER A 2. INTRODUCTION The City of Cordova, Alaska now depends almost entirely on petroleum fuel for its electrical energy and heating needs. While present and future electrical energy demands could be met by upgrading the existing diesel generation system, there is a critical concern that an appreciable increase in diesel fuel costs will result in prohibitive energy rates for both residential and commercial consumers. Therefore, the Alaska Power Authority and the City of Cordova want to identify and pursue that power supply alternative which has the best prospect of reducing the community's dependence on petroleum fuel while satisfying present and projected energy needs. There have been a number of preliminary studies related to Cordova's energy needs. Most recently a Reconnaissance Study of "Energy Requirements and Alternatives for Cordova", prepared for the Power Authority in June 1981, identified a number of potential alternatives which required detailed examination. As a result, preparation of this Feasibility Analysis, for the Power Authority and City of Cordova, began on November 16, 1981. 2.1 STUDY PURPOSE The purpose of this Detailed Feasibility Analysis is to formulate the optimal plan for providing the least cost electrical power to the City of Cordova. The overall study will be accomplished in two phases. This report addresses Phase I in which the institutional, economic, environmental and technical aspects of selected alternatives are analyzed in sufficient detail to permit selection of the preferred plan for energy generation. During Phase II, development and optimization of this preferred plan will include collection of required field data, detailed environmental and geotechnical evaluation, detailed technical planning, and the preparation of license/permit applications required to initiate design and construction. Specifically, during this phase of the Study, an in-depth assessment and comparison has been made of those coal, hydroelectric and transmission intertie alternatives (individually and in combination) considered potentially feasible solutions for Cordova's energy needs. Viable alternatives were then used in the formulation of energy supply plans for which electric power costs and environmental and social impacts were minimized. Evaluation of these alternatives will result in the selection of the preferred plan for development and optimization during Phase II. 2-2 STUDY ASSUMPTIONS AND CONSTRAINTS (To be provided in the Final Phase I Report) STONE & WEBSTER A 2.3 STUDY METHODOLOGY The inclusion of coal, hydroelectric, and transmission intertie alternatives in this analysis provides an unusually wide spectrum of energy options, each of which is frequently the subject of an individual investigation. Therefore, Phase I is being accomplished as a series of site specific independent studies which are evaluated (individually and in combination) and compared with the base case of continued reliance on diesel and heating oil. Each alternative is developed and documented in sufficient detail to provide an acceptable level of confidence in the conclusions reached. However, it should be noted that Phase I timing and schedule prohibited a number of field investigations which are required to validate technical assumptions. This is particularly true of detailed environmental, geotechnical and hydraulic investigations which will be recommended for early accomplishment in Phase II. To ensure that selection of the preferred plan for Cordova is timely and cost effective, each alternative identified for investigation has been subjected to a sequential screening process. This process has been used to permit the earliest possible elimination of those alternatives considered either economically of technically infeasible, as well as those which are considered to be an unacceptable development risk. As shown graphically in Figure 2.3-1, each alternative must survive four successive screenings to be considered in the final preferential analysis. FATAL FLAW ANALYSIS On the basis of preliminary siting and design parameters, each alternative is first subjected to a comprehensive screening to ensure environmental, geotechnical and hydrologic requirements can be met. Alternatives which present unacceptable risks in these areas are eliminated from further study. Secondly, an alternative that cannot provide a significant percentage of the yearly power requirement for Cordova is considered unacceptable. An alternative may also be rejected if it exhibits a number of severe defects or undesirable characteristics, which by themselves are not "fatal", but in combination with each other, preclude the development of that site. TECHNICAL FEASIBILITY Conceptual development and design is performed for remaining alternatives. Those which are infeasible because of technical constraints such as siting, design or construction, are identified and no longer pursued. ECONOMIC EVALUATION In this screening, capital cost estimates are developed for all surviving alternatives. These estimates together with those for fuel, operations, maintenance and other system variables are used to develop total life cycle (present worth) costs in accordance with Power Authority economic analysis guidelines. Alternatives with significantly higher costs are subjected to a simplified sensitivity analysis to determine if they would be competitive in other potential power demand scenarios. Those that remain uncompetitive are eliminated from further study. STONE & WEBSTER A RISK ACCEPTABILITY To ensure remaining alternatives represent viable solutions to future power needs, they are subjected to a detailed risk and sensitivity analysis. In these investigations, all parameters which might effect ranking of the alternative are reviewed, and the alternatives reevaluated based on the widest possible range for each variable. Sensitivity to each variable is determined, and the risks associated with selection of the alternative are identified. PREFERENTIAL RANKING Those alternatives which are economically sound, technically viable, and which present no obvious fatal flaws or unacceptable environmental or technical risks, are evaluated further to determine a preferential ranking. The alternatives are ranked in order of technical, environmental, economic and social preference. Input from the public and from governmental agencies will weigh heavily in determining social and environmental acceptability. If the earlier sensitivity analysis indicated a potential change in rankings due to varying parameters, a subjective assessment is made to determine the probability of actual rank order change, and "most probable" rankings are established. On the basis of this final rank order analysis, a single best plan for vordova will be recommended for Phase II optimization. STONE & WEBSTER A gcozscow SCREENING SEQUENCE FATAL FLAW : CORDOVA POWER SUPPLY e ENVIRONMENTAL ALTERNATIVES ¢ GEOTECHNICAL ¢ HYDROLOGIC TECHNICAL © SITING CONSTRAINTS e CONCEPTUAL DESIGN ECONOMIC © COST ESTIMATES e ECONOMIC ANALYSIS RISK ¢ RISK ANALYSIS © SENSITIVITY ANALYSIS PREFERENTIAL RANKING ¢ INDICATOR EVALUATIONS © COMPARATIVE SELECTION PREFERRED PLAN OPTIMIZED IN PHASE II Figure 2.3-1 SEQUENTIAL SCREENING PROCESS STONE & WEBSTER A 2.4 ALTERNATIVES INVESTIGATED Based on the June 1981 "Reconnaissance Study of Energy Requirements and Alternatives", three principal alternatives were originally selected for detailed analysis. These were: Coal-Fired Generation at Cordova Hydroelectric Generation at Power Creek Transmission Interties to Solomon Gulch Initial analysis of these alternatives, and detailed discussions with the Power Authority, City of Cordova and Cordova Electric Cooperative, indicated that additional alternatives should be evaluated. These additions generally represent variations of alternatives either already under review, or previously reviewed in the Reconnaissance Study. However, the study scope was also expanded to include analysis of Regional power supply alternatives not previously considered. As a result, the expanded Feasibility Study includes an analysis of the following nineteen alternatives: DIESEL GENERATION BASE CASE DOl Existing Diesel Plant DO2 New Diesel Plant COAL-FIRED GENERATION COl Single "Land" Unit Co2 Single "Barge-Mounted" Unit CO3 Dual "Land" Units CO4 Dual Fluidized Bed Units CO5 Dual Units at Katalla HYDROELECTRIC GENERATION HOl Power Creek HO2 Silver Lake HO3 Allison Lake HO4 Crater Lake HO5 Sites with less than 3 MW Capacity TRANSMISSION LINES TOl Cordova to Solomon Gulch - Coastal Route TO2 Cordova to Solomon Gulch with tap to Silver Lake TO3 Cordova to Solomon Gulch - Copper River Route TO4 Cordova to Bering River Coal Fields TO5 Cordova to Solomon Gulch - Submarine Cable T06 Teeland-Palmer-Glennallen TO7 Cordova to Whittier - Submarine Cable A detailed discussion of each of these alternatives is provided in the sections which follow. STONE & WEBSTER da 3. CURRENT DIESEL GENERATION (To be provided in the Final Phase I Report) STONE & WEBSTER A 4, ELECTRICAL ENERGY FORECASTS Local and regional annual energy and peak load power requirements and availability were determined to provide a reasonable and common basis for development of energy alternatives for Cordova. To permit later analysis of the sensitivity of alternatives to predicted demands, forecasts were also developed for a wide range of potential electric space heating scenarios. Where possible, the forecasts provided in this analysis have been developed by validating and supplementing previous local and regional power studies. Of particular value, in this effort, was the June 1981 Reconnaissance Study of "Energy Requirements and Alternatives for Cordova" prepared for the Power Authority; and, the March 1981, Interim Feasibility Report on "Electric Power for Valdez and the Copper River Basin", prepared by the U.S. Army Corps of Engineers. A complete analysis and forecast of local and regional electrical energy requirements and availability will be provided as an Appendix to the Final Phase I _ report. The following sections provide a summary of the methodology, data and recommendations developed thru March 10, 1982. 4,1 CORDOVA ANNUAL AND PEAK DEMANDS 4.1.1 Cordova Non-Space Heating Forecasts The Reconnaissance Study forecast of energy demands (without conversion to electric space heating), was reviewed and found to generally represent a reasonable estimate of the future growth of power requirements for Cordova. The mean-growth scenario for the Cordova Electric Cooperative (CEC) service area was selected as the appropriate forecast of future demands, because of the minimal difference in peak loads between low and mean-growth and because the high-growth scenario is based on the specific development of petroleum reserves. This latter forecast should be treated as a special case in which additional power sources should not be developed unless such discoveries of reserves actually occurs. After extrapolating Reconnaissance Report data for the total study period and adding an assumed Chugach Fisheries load of 1 MW beginning in 1982, CEC's annual non-space heating requirements are projected to increase to 38,300 MWh by the year 2002 with a peak demand estimated at 9.2 MW. Annual energy and peak demands are provided in Table 4.1-1. STONE & WEBSTER A 4.1.2 Cordova Space Heating Forecasts The current high cost of electricity dictates that almost all of CEC's residential customers use heating oil or wood for space heating. Therefore, if future electricity is provided at significantly lower cost the use of electric space heating can be expected to increase. To assess the magnitude of this potential increase an independent review of potential residential heating was conducted as part of this Feasibility Study. This analysis is based on the economic factors which impact on the conversion and use of electric space heating. The net present value of electric heating and heating oil were compared and the investment "pay back" for conversion estimated. Analysis indicates that significant use of electric space heating is not likely to occur unless the average cost of electricity to the residential consumer is reduced from its present 20¢ per kWh range to a threshold of about 6¢ per kWhr. Other factors, such as fuel storage and delivery, cleanliness of the fuel, and minimal maintenance, may alter these conclusions to some degree although their impact is not likely to be significant. As shown in Table 4.1-1 electric heating demands were computed for scenarios with varying consumer power costs ranging from 2¢ to 6¢ per kWhr. It must be emphasized that since both actual consumer costs and implementation of individual economic options are subject to a variety of external influences, power cost is less significant than is the extent of electrical space heating represented by each scenario. These expectations of space heating utilization on which the analysis is based are summarized in Table 4.1-2. Preliminary conceptual designs for energy supply alternatives, are based on the annual consumption and peak demand projected for the 4¢ power level. In this scenario all new construction would utilize electric heating, portable heaters would be used to provide supplemental heat in most existing family units, while only a minimum number of these units would have been converted to full service electric heating. At this level CEC's annual power requirements in 2002 would be 50,900 MWhr with a peak demand of 12.0 MW. STONE & WEBSTER A TABLE 4,1-1 CORDOVA POWER REQUIREMENT INCLUDING ELECTRIC HEATING FOR RESIDENTIAL CUSTOMERS 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Energy (103 MWh) Forecast (1) 17.5 18.2 20.5(2)21.2 22.0 21.8 22.3 23.3 23.8 24.7 26.0 27.7 28.9 29.6 30.1 31.0 31.8 33.0 34.5 35.8 36.8 38.3 w/heating load: at 6¢/kWh 17.5 18.2 20.5 21.2 22.5 22.7 23.7 25.2 26.2 27.6 29.5 31.7 33-4 34.7 35.8 37.4 38.8 4O.6 42.8 44.9 46.5 48.7 at 4¢/kWh 17.5 18.2 20.5 21.2 23.0 23.9 24.4 27.4 28.4 29.8 31.7 34.1 35.7 37.0 38.2 39.7 41.1 42.9 45.1 47.1 48.7 50.9 at 3¢/kWh 17.5 18.2 20.5 21.2 23.3 24.4 26.2 28.5 29.5 31.0 32.8 35.1 36.8 38.1 39.3 40.8 42.2 44.0 46.2 48.2 49.9 52.2 at 2¢/kWh 17.5 18.2 20.5 21.2 23.8 25.3 27.6 30.4 31.4 32.3 34.7 36.9 38.6 40.0 41.1 42.6 44.0 45.9 48.1 50.1 51.8 54.0 Demand (MW) Forecast (1) 3.5 3.6 4.7(2)4.9 5.0 5.1 5.3 5.4 5.6 5.8 6.0 6.8 7.0 7.2 7.4 7.6 7.9 8.1 8.3 8.6 8.8 9.2 w/heating Load: at 6¢/kWh 3-5 3.6 4.7 4.9 5.0 5.1 5.3 5.4 5.6 5.8 6.0 6.8 7.2 7.6 7.9 8.3 8.8 9.2 9.5 10.1 10.4 11.1 at 4¢/kWh 3.5 3.6 4.7 4.9 5.0 5.1 5.3 5.7 6.2 6.5 6.9 7.7 8.1 8.5 8.8 9.2 9.7 10.1 10.4 11.0 11.3 12.0 at 3¢/kWh 3-5 3.6 4.7 4.9 5.0 5.1 5.6 6.0 6.5 6.8 7.2 8.0 8.9 8.8 9.1 9.5 10.0 10.4 10.7 11.3 11.6 12.3 at 2¢/kWh 3-5 3-6 4.7 4.9 5.0 5.3 6.1 6.6 7.2 7.5 7.9 8.7 9.1 9.5 9.8 10.2 10.7 11.1 11.4 12.0 12.3 13.0 (1) Source: Reconniassance Study of Energy Requirements for Cordova, June 1981. (2) Assumption of Chugach Fisheries load by CEC. STONE & WEBSTER A TABLE 4.1-2 RESIDENTIAL ELECTRIC HEATING UTILIZATION Consumer New Existing Residential Units Annual Electrical Electricity Cost Residential Supplemental Use of Full Conversion to Heating Energy (103 MWh) (¢ per kWh) Units Portable Heaters Electrical Heating (year 2002) 6 Most Minimal None 10.4 4 All Most Minimal 12.6 3 All All 15 percent 13.9 2 All All 30 percent 15.7 STONE & WEBSTER A 4,2 REGIONAL AVAILABILITY AND DEMAND FORECASTS To provide a basis for analyzing regional power requirements for Palmer, Glennallen, Valdez and Cordova, power supply and load projection data is being analyzed for Copper Valley Electric Association, Matanuska Electric Association, Chugach Electric Association, and for the Anchorage Municipal Light and Power Company for the period 1982 through 2002. Power supply, load projection and transmission intertie data required in this analysis, is being developed using existing studies and information, supplemented by field evaluation. In addition, potential future regional resources including Beluga Coal Field and Susitna hydroelectric power will be evaluated as alternative power sources for Cordova. The appropriate Cordova share of capital and operations costs of transmission lines to the Anchorage area will be developed for each regional plan investigated. Results of these regional forecasts will be provided in the Final Phase I Report. 4.3 SELECTED EVALUATION PARAMETERS Using the rationale developed in Section 4.1.2, initial evaluation and comparison of energy alternatives for Cordova has been based on meeting an annual power consumption requirement of 50,900 MWhrs with a peak of 12.0 MW. Rank order sensitivity to changes in these demands is being determined utilizing a low demand scenario with no space heating of 38,300 MWhrs annually with a peak of 9.2 MW, and a high demand scenario which would require 62,000 MWhrs annually with a peak of 15.0 MW in the year 2002. In addition, to provide acceptable system reliability, all non-diesel alternatives include provision of an emergency diesel back-up capability of 7.6 MW. As described in Section 5.8, this back-up would meet Cordova's emergency requirements in the event of primary system outages. STONE & WEBSTER A 5. OPTIMIZED DIESEL GENERATION Diesel generator units have been used for base load, stand-by, and auxiliary power generation in Alaska for many decades. Their reliability and simplicity of operation make them particularly well suited for communities where load demands are low and where there are no transmission lines to cheaper sources of power. Cordova is currently such an area and the Eyak Lake diesel plant represents a technically acceptable means to meet the area's electrical needs. 5.1. METHODOLOGY, PARAMETERS To provide the most economical base case, suitably comparable to other alternatives, two diesel generation alternatives were conceptually designed, estimated, and analyzed for complete life cycle costs. The existing plant modification (D01) and the new plant (D02), display advantages distinct from each other. Based upon the similar life cycle costs of the two alternatives, either could justifiably be developed in Cordova, depending upon the preference of the local utility. However, for the purpose of this feasibility study, the base case will be chosen as the most economical life cycle cost alternative. If life cycle costs are too close to clearly inditate which alternative would be least expensive, the base case will be chosen as the alternative with lowest capital costs. 5.2. TECHNICAL ANALYSIS AND SYSTEM DESCRIPTION 5.2.1. Existing Diesel Plant Modification (DO1) Alternative DOl consists of renovation and expansion of the existing Eyak Lake facility. The final configuration of the plant at the end of the study period, year 2002, will contain four 2500 kW diesel generator units, three 1250 kW units, and two 575 kW units, for a total generating capacity of 14,900 kW. Fuel is transported to the plant by tank truck. 5.2.2. New Diesel Plant (D02) Alternative DO2 consists of the addition of a new diesel generating plant near Fleming Spit. The new plant would be run in parallel with the existing Eyak Lake facility until retirement of the last Eyak Lake unit in 1996. The final arrangement of the new plant, in the year 2002, will contain the same number and size of diesel generators as DOl. Fuel oil will be transported to the site by underground pipeline from the oil supplier's current storage facilities. 5.3. ENVIRONMENTAL AND SOCIOECONOMIC ISSUES Investigation indicates that no environmental or socioeconomic "fatal flaws" exist for any diesel alternative. A full discussion of these technical areas will be provided in the Final Phase I Report. =10= STONE & WEBSTER A 5.4. SITING, CONCEPTUAL DESIGN AND CAPITAL COSTS 5.4.1. Existing Diesel Plant Modifications (D01) The current Eyak Lake diesel generating facility is sited on a centrally located geotechnically sound, land area. Useable equipment and portions of the foundation of the existing building reduce the initial capital expenditures which would be required to construct a new diesel generating station. Three diesel generating units from the existing plant are considered useable in the modified base case plant. These units are: Unit No. 1 - 1900 kW Unit No. 2 - 2650 kW Unit No. 3 - 2500 kW Cost estimates include overhaul of these existing units to bring them to optimum maintenance standards. New 575 kW, 1250 kW, and 2500 kW diesel generator units are added as Cordova's electrical demands increase. When the existing three diesel units reach retirement, they will be replaced by 2500 kW units. The installation schedule for all units is shown in Table 5.4-1. Modification of the existing facility will include replacement of the existing plant with a larger building. An increased building eave height (22 ft) will enhance diesel generator maintenance by allowing installation of an overhead bridge crane. Much of the piping and electrical controls would be rearranged to promote ease of operation and safety. Air cooled radiators would be installed to- provide jacket water cooling for all the diesel engines and to eliminate the need for the cooling pond and pumphouse north of the plant. The cooling pond would be filled in to prevent its possible pollution of Eyak Lake, while the pumphouse could either be removed, or its equipment removed and the building used for storage. The existing 115,000 gallon primary fuel oil storage tank will be replaced with two 250,000 gallon tanks, each diked to contain any oil leakage or spill. These larger tanks are needed for the increasing plant capacity over the extended study period, and may allow slightly lower fuel costs due to larger quantity purchases. Based on preliminary site investigations, a large portion of the existing electrical switchgear is suitable for reuse. Prior to implementing alternative DO1, a more thorough structural analysis of the existing building and diesel generator foundations must be made to accurately assess their structural integrity. The preliminary conceptual design for alternative DOl is shown in Figures 5.4-1 and 5.4-2, while the associated capital expenditures are tabulated in Table 5.4-1. The total present worth of the capital costs for alternative DOl are $13,300,000. STONE & WEBSTER A Tle 5.4.2 New Diesel Plant (D02) Alternative DO2 includes construction of a new diesel plant just north of Fleming Spit which would initially be operated in parallel with the existing Eyak Lake diesel facility. The Eyak Lake plant would be phased out of operation by 1996. The area near Fleming Spit was chosen for the new plant site because of its isolation from residential areas, reasonable proximity to the fuel source, and sufficient area for plant development. The entire area is within the tsunami zone of the 1964 earthquake. Therefore, any new facility sited along the coast of Orea Inlet should be sited with the foundation at least 32 feet above low tide. The new diesel plant would be installed on an existing bedrock bench north of Fleming Spit, which would provide protection from tsunamis and better foundation characteristics. The earthwork and potential rock blasting required for alternative DO2 will have a significant capital cost not associated with alternative DOl. The site would contain a new 70 ft by 175 ft building with 22 ft eave height. Two new 575 kW and one 1250 kW diesel generator would be installed immediately after building erection. Unit 3 (2500 kW) from the Eyak Lake plant would then be relocated to the new facility. Unit 3, installed in 1978, is the newest of the existing units, and would be placed in the new plant to improve its maintenance and operation, and to speed the retirement of the Eyak Lake facility. The 575 kW unit would have a "black-start" capability which allows the unit to start when no other units are operating. New 1250 kW and 2500 kW units would be added as Cordova's electrical demands increase and the units at Eyak Lake plant are retired. By 1996, the Eyak Lake facility will be completely retired, and the new plant will contain two 575 kW, three 1250 kW, and four 2500 kW diesel generating units. The installation schedule is provided in Table 5.4-2. = The new plant would be approximately one mile from the oil supplier's bulk storage area, which would permit fuel supply by pipeline. In addition, one 250,000 gallon fuel oil storage tank would be installed at the new plant to provide reserve capacity. This is half the reserve oil storage designed for alternative DOl1, which is supplied by truck. Diesel engine cooling is provided by independent air cooled radiators for all units. The cooling loops will be cross-connected with similarly sized radiators to provide redundancy and improve reliability. Alternate DO2 includes a minimum amount of renovation of the existing Eyak Lake plant to ensure its safe operation until plant retirement in 1996. However, renovation would not be nearly as extensive as for alternative DOl. Included in the Eyak Lake plant renovation is the overhaul of diesel units 1 and 2, piping rework, electrical rework, and the addition of a diked replacement fuel oil storage tank. The capital expenditures for alternative DO2 are listed in Table 5.4-2, and the total present worth capital costs are $14,500,000. STONE & WEBSTER A -1l2- OIL RETAINING DIKE EYAK LAKE |] rump HOUSE |—|———_ 250,000 GAL. TANKS CJ FUEL TRUCK UNLOADING FACILITY EXISTING BUILDING TO BE REPLACED BY NEW STRUCTURE SUBSTATION DIESEL PLANT Figure 5.4-1 MODIFIED DIESEL PLANT LAYOUT (DO1) A0382044 STONE & WEBSTER a A0382046 RADIATOR (TYP) — = — = [—- = c= i EXISTING CITY SHOPS TO BE REPLACED BY 2,500 KW UNITS UPON RETIREMENT 2,500 Kw SOUND ABATEMENT PARTITION 1,250 1,250 3 EXISTING UNIT 3 MAINTENANCE BRIDGE CRANE ROLL UP DOORS INSULATED (TYP) 3, GAL. FUE D, a WITH 22’ EAVE HEIGHT ae EUELO1L DAY. MUFFLER (TYP) NEW 70’ x 175’ INSULATED BUILDING TANK W/FIRE PROTECTED ENCLOSURE Figure 5.4-2 MODIFIED DIESEL PLANT EQUIPMENT ARRANGEMENT (DO1) STONE & WEBSTER A TABLE 5.4~-1 . DOl - EXISTING DIESEL PLANT MODIFICATION CAPITAL EXPENDITURE SCHEDULE Present Worth Expenditure 1982 $ Year Money Spent Capital Cost Major Work Items Performed 195,000 1982 $ 189,000 Add 575 kW diesel generator, black-start Add 550 gal day tank 7,759,000 1983 7, 314,000 Remove existing diesel units 7, 8, and 9 Federal PSD application Add 575 kW diesel generator, black-start Add 550 gal day tank Remove existing large fuel oil storage tank Add two new 250,000 gal storage tanks Remove existing plant building Erect new 70 ft x 175 ft building Install bridge crane Site earthwork and partial foundation rework Add 1250 kW diesel generator Rework cooling water piping for diesel units Relocate exhaust mufflers for diesel units Overhaul diesel units 1 and 2 Add 3,000 gal waste oil tank General electrical and mechanical rework 2,982,000 1992 2,154,000 Retire diesel unit 1, 1900 kW Add 1250 kW diesel generator Add 2500 kW diesel generator General electrical rework 3, 312,000 1996 2,126,000 Retire diesel unit 2, 2650 kW Add two 2500 kW diesel generators 858,000 1998 $ 519,000 Add 1250 kW diesel generator 1,656,000 1999 973,000 Retire diesel unit 3, 2500 kW Add 2500 kW diesel generator TOTAL DO] PRESENT WORTH CAPITAL COST $13,275,000 Therefore use $13, 300,000 STONE & WEBSTER A Expenditure 1982 $ 8,267,000 2,808,000 5,227,000 762,000 1,471,000 Year Money Spent 1983 1992 1996 1998 1999 TOTAL DO2 PRESENT WORTH CAPITAL COST TABLE 5.4-2 DO2 - NEW DIESEL PLANT Present Worth Capital Cost $7,792,000 2,029,000 $3,355,000 461,000 864,000 $14,501,000 CAPITAL EXPENDITURE SCHEDULE Major Work Items Performed Existing Eyak Plant: Install 250,000 gal fuel tank Overhaul units: 1, 1900 kW; 2, 2650 kW Rework piping, air plenum and electrical New Fleming Spit Plant Site preparation, earthwork, and foundations Federal PSD application Erect new 70 ft x 175 ft building with crane Electrical and switchyard installation Add new 250,000 gal fuel oil storage tank Install oil pipeline to Chevron tank farm Relocate unit 3, 2500 kW, with new radiator Add two 575 kW diesel generators, black-start Add two 550 gal day tanks Add 1250 kW diesel generator Add 3,000 gal day tank Add 3,000 gal waste oil tank Existing Eyak Plant Retire unit 1, 1900 kW New Fleming Spit Plant Add 1250 kW diesel generator Add 2500 kW diesel generator Electrical switchyard expansion Existing Eyak Plant Retire existing Eyak Lake diesel generating plant New Fleming Spit Plant Add two 2500 kW diesel generators Add 1250 kW diesel generator Retire unit 3, 2500 kW Add new 2500 kW diesel generator Therefore use $14,500,000 STONE & WEBSTER A 5.5 FUEL SUPPLY AND COSTS Presently fuel oil is barged to Cordova and unloaded at the Chevron bulk storage terminal. From the Chevron storage facility, the diesel fuel is transported by truck to the Eyak Lake generating plant. The present cost of this trucked fuel is $1.086 per gallon. This method of transportation would continue in alternative DOl. However, prices could be reduced with purchases of larger fuel quantities. Alternative DO2 would use pipeline transportation of fuel to the new plant. Deducting previous truck transportation costs, it is estimated that the current price of piped fuel oil would be reduced to $1.065 per gallon. Oil storage facilities at the new plant (D02) would consist of a 550 gallon day tank for each 575 kW unit, one 3,000 gallon day tank for the remaining units, one 3,000 gallon waste oil tank, and one 250,000 gallon storage tank. Modification of the Eyak Lake plant fuel oil system (DO1) will add two 550 gallon day tanks, one 3,000 gallon waste oil tank, and two 250,000 gallon fuel storage tanks. Fuel storage and supply systems for both alternatives DOl and DO02 have major advantages over the system presently in use at the Eyak Lake plant. Of particular note, is storage design which will prevent oil spills, promote safety, and increase ease of operation and maintenance. 5.6 MAINTENANCE AND OPERATION (To be provided in Final Phase I Report) 5.7 ECONOMIC ANALYSIS The capital costs for diesel generation alternatives DOl and DO2 are based upon the expenditure schedules shown in Tables 5.4-1 and 5.4-2, respectively. These present worth capital costs are $13,300,000 for the existing diesel plant modification (D001), and $14,500,000 for the new diesel plant (D02). Fuel costs were assumed to be $1.09 per gallon for option DOl and $1.07 per gallon for DO2. Parts and miscellaneous expenses, excluding labor, were based on Cordova Electric Coorperative records, escalated to a 1982 cost of 4.8 mils per Kwh. The plant staff, including supervision, was assumed to consist of 8 people for DOl and 9 people for DO2. The average salary per employee including benefits, was assumed to be $25 per hour. The total present worth life cycle costs for each alternative is: DOl $176,900,000 DO2 $176,900,000 STONE & WEBSTER A == The life cycle cost analysis shows alternatives DOl and D02 to be identical. DOl has lower capital costs while alternative DO2 has lower fuel costs due to pipeline transportation of fuel. Thus, either alternative could reasonably be justified for use as Cordova's base case. Alternative DOl has been selected for base case comparison because there are less geotechnical and environmental risks associated with the development of the existing plant site, and because of its lower capital cost. 5.8 BACK-UP DIESEL PLANT The preferred energy plan for Cordova must be reliable and capable of meeting electrical demands at all times. To accomplish this, the energy supply system would have to be either completely redundant or have a suitable back-up from a separate power source which could meet electrical demands during a primary system outage. Since transmission interties, hydroelectric and coal generation are not fail-safe systems, back-up diesel generator capability is proposed as the reserve energy source for these alternatives. To provide back-up power at minimum cost, the existing Eyak Diesel Plant would be removed. Diesel generator units 1 and 2, at 1900 kW and 2650 kW, respectively, would be rebuilt; unit 3 at 2500 kW would remain operational and a new 575 kW "black-start" unit would be added. This would give the emergency diesel plant a 7625 kW capability which should be sufficient to provide emergency or reserve power after the new power supply facility is on-line. Figure 4.1-1 indicates 7625 kW would meet Cordova'ts peak emergency requirements through 1996. Peak requirements in excess of 7.6 MW, which occur after 1996, would be met by either load-shedding or use of emergency generators now available to principal Cordova industrial and municipal energy users. Modification of the existing Eyak Diesel Plant would be initiated in 1985. A 110 ft by 50 ft mid-section of the old building would be dismantled and replaced with a 110 ft by 70 ft new insulated steel building with a 22 ft eave height. The existing fuel oil storage tank would be replaced with a new 250,000 gallon tank contained by a surrounding dike, and third, the new 575 kW unit would be installed on a new foundation and tied into new electrical control and switch gear. Most of the existing piping would be reworked and a new 3,000 gallon waste oil tank would be installed. A new air-cooled radiator would be added to end reliance on the existing cooling pond and pump house. Finally, the 1900 kW and 2650 kW diesel generator units would be overhauled. The conceptual design of the back-up Eyak Diesel Plant renovation is shown in Figures 5.8-1 and 5.8-2. The capital cost of this emergency plant is estimated at $3,400,000, and is included as part of all non-diesel alternatives. STONE & WEBSTER dB STS A0382045 EYAK LAKE —— 250,000 GALLON FUEL OIL TANK WITH DIKE EXISTING BUILDING TO BE REPLACED BY NEW STRUCTURE SWITCHYARD CEC BUILDING CITY SHOPS AREA Figure 5.8-1 BACK-UP DIESEL PLANT LAYOUT STONE & WEBSTER A A0382043 REPLACE EXISTING STRUCTURE RADIATOR (TYP) WITH NEW 70’ x 110’ INSULATED STEEL ENCLOSURE (22’ EAVE HEIGHT) 3,000 GAL FUEL OIL DAY TANK W/FIRE RETARDANT ENCLOSURE ELECTRICAL & Orrick MAINTE- NANCE CEC BUILDING AREA LAYDOWN CITY SHOPS AREA oO O=+—- Murr ter (Typ) Figure 5.8-2 BACK-UP DIESEL PLANT EQUIPMENT ARRANGEMENT STONE & WEBSTER A 6. COAL GENERATION Coal-fired steam electric power plants are a proven means of providing low cost, reliable electric power. Such plants can be constructed to meet a wide range of energy demands using fuel which varies in quality from low-Btu lignite to high-Btu anthracite. Given Cordova's energy demands and available coal sources, a coal-fired power plant can be designed to minimize socioeconomic and environmental impacts at reasonable cost. Because coal-fired power generation is an established technology with decades of proven reliability, given Alaska's vast coal reserves, coal generation may provide a competitive means of providing power to Cordova. Five coal generation options have been evaluated for Cordova, and are described below. 6.1 METHODOLOGY, PARAMETERS To develop the most competitive coal alternatives, two land based coal-fired plants, one sited near Cordova and the other at the Bering River coal field have been evaluated. Additionally, a coal-fired unit completely pre-assembled and permanently mounted on barges, was considered. Based on site and configuration selection, conceptual designs of coal-fired power plant alternatives were developed. These addressed five major variables: 1) number and size of units; 2) type of boilers; 3) method of plant cooling; 4) means of coal handling, and 5) emission control requirements. Environmental and technical requirements, dictated emission control, coal handling, and plant cooling equipment selection, while the number of units and type of boilers were varied to provide a wide range of potential options. Plot plans and calculations were prepared to allow specific estimates of major capital expenditures, fuel costs, and operation and maintenance costs, and the preparation of life cycle costs for all coal generation alternatives. 6.2 KATALLA (C05) This coal generation option is a land based mine-mouth power plant located at the Bering River coal field near Katalla. Power to Cordova would be provided by approximately 60 miles of transmission line. The requirement for a significant length of transmission line is economically balanced by coal transportation being restricted to relatively short distances. The Bering River coal field is not developed at this time. However, Chugach Natives, Inc. (CNI) are presently planning a major coal mine and port facility to supply this coal to Pacific Rim countries. CNI would be very interested in either receiving power from a mine-mouth power plant, or providing coal for a plant located in Cordova. To date, the progress made on development of the Bering River coal fields has not resulted in either a definitive mine design or construction schedule. STONE & WEBSTER A -15- Without a firm plan for the Bering River coal mine, a power plant site could not be selected and a preliminary conceptual design could not be formulated. Additionally, without any firm schedules for the planned mine it is difficult to predict when a mine-mouth power plant could become available. Because of these uncertainties an accurate economic evaluation could not be prepared. However, based on the assumptions which follow, an approximate present worth life cycle cost was computed for this alternative. The economic analysis of alternative C05 is based on the following assumptions: The coal heating value is 12,000 Btu/lb, and, according to Chugach Natives, Inc., coal costs at the mine will be 14 percent more per Btu than Healy coal at the Usibelli mine. The Bering River power plant will begin commercial operation January l, 1990, and will have a 12 MW capacity available for Cordova. This is conservative since if the unit supports both Cordova and the coal mine, it would benefit from economy of scale. However, only the costs associated with Cordova's demand (12 MW) should be passed on to the City of Cordova, with the remainder being absorbed by the mine operators. The transmission losses from Bering River to Cordova will be 5 percent of the line power. The site preparation requirements are estimated at $10,000,000, and coal handling equipment at $1,000,000. The power plant would consist of two 6 MW units with air-cooled condensers (see Section 6.3.3.4 for a detailed description). Based on these assumptions, the present worth life cycle costs, including the transmission line to Cordova, is $164,000,000. Although the results of alternative C05's economic analysis are attractive, the estimate contains more risk than estimates associated with other coal-fired alternatives. The exact site and size of the coal-fired plant are unknown, coal prices are not established, and the date of coal mine development and associated power plant operation are uncertain. Chugach Natives, Inc. are presently in the stage of preparing a prefeasibility study on the Bering River coal mine. However, conceptual designs will not be available until mid-1983 and construction schedules will follow in 1984. Until more specific information is available, further definitive investigations of this alternative can not be accomplished. 6.3 CORDOVA LAND OPTIONS (C01, C03, CO4) This section includes descriptions and analyses of the following three land-based coal-fired power plant alternatives, each of which would be located at the Fleming Spit site. STONE & WEBSTER A COl - single 12 MW unit plant. CO3 - dual 6 MW unit plant with stoker-fired boilers. CO4 - dual 6 MW unit plant with fluidized bed boilers. A generalized site plan, a plant layout, and a perspective view of the typical Fleming Spit coal-fired facility are provided in Figures 6.3-l, 6.3-2, and 6.3-3 respectively. The power plant would be located on a bench cut out of the rock quarry at approximately 50 feet above low tide sea level, and coal storage would be at the 25 feet level. The coal unloading dock is constructed by backfilling behind sheet piling set 100 feet off the present shoreline. For on-site ash disposal, a landfill area is contained by a built-up dike in the low-lying area near the discharge of Fleming Creek. 6.3.1 Technical Analysis and System Description There are two primary systems to burn coal to create steam in the generation of electricity. Stoker systems, common in smaller boilers, feed coal onto a moving grate within the boiler where the coal is burned completely as it passes through. In pulverized coal systems, the coal is ground to a very fine dust and burned in suspension as an air-coal mixture. While the pulverized systems burn coal more efficiently, the stoker system's lower capital and operating costs make them more cost effective for small boilers of the size contemplated for Cordova. Equipment to transfer the coal to either the stoker or pulverizer also requires a significant capital expenditure for items such as barge or railroad car unloading facilities, stacking/reclaiming equipment, coal storage facilities, conveyors, transfer houses, coal crushers’ and auxiliaries. A third and relatively new coal burning system is based on fluidized bed combustion. Although this technology is new to power stations, fluidized bed chemical reactors have been in use for several decades in the chemical and petroleum industries and fluidized bed combustion is currently being commercialized for industrial boilers. These boilers have a layer of small, noncombustible particles (limestone in the case of high sulfur coal combustion) which rest on a distribution plate. Combustion air is forced through the nozzles or openings in the plate and turbulently mixes the bed material giving it a fluid-like motion. Fuel (coal) is mixed with the combustion air entering the bottom of the bed, and is burned in the bed. Fluidized bed combustion offers the following advantages: The coal is burned in the bed in close contact with the limestone. The limestone reacts with the sulfur dioxide in the flue gas to form calcium sulfate, a relatively inert material which is removed with the ash. Virtually all the sulfur is captured by the lime, and very little sulfur dioxide is discharged with the flue gases. The need for flue gas desulfurization for high sulfur coals is thus eliminated. Combustion normally takes place between 1500 F and 1750 F, hundreds of degrees below the point where atmospheric nitrous oxide formation becomes troublesome. STONE & WEBSTER A a1 = High heat transfer coefficients are obtained by solids/metal contact, permitting more compact boiler designs. The ability to burn coarser sized fuel reduces the costs of fuel preparation in comparison to pulverized coal systems. Low combustion temperatures minimize or eliminate ash slagging problems. Virtually any type of combustible material may be burned by properly adjusting the type and particle size of bed material, fluidizing velocity, feed methods, and rate of feed. Atmospheric, circulating and pressurized systems are being developed for fluidized bed combustion. In an atmospheric fluidized bed combustor (FBC) combustion takes place at or near ambient pressure, while the pressurized version operates at from 3 to 16 atmospheres of pressure. In a circulating bed, the bed material is circulated outside the combustion zone and used as a heat transfer medium. Atmospheric FBC boilers are currently being commercialized, with several demonstration plants under construction and in operation. The pressurized FBC boilers offer higher efficiencies, better limestone utilization and more compact design than their atmospheric counterparts, but are quite complex and still in the early development stage. Circulating fluidized beds are in commercial operation in Europe and are rapidly being developed in the United States. Recent technological advances in coal-fired steam electric generating facilities have focused upon control of air pollution. With primary emphasis on control of sulfur oxides, nitrogen oxides, and particulates. Reduction of sulfur oxides in exhaust gases can be accomplished by either mechanical cleaning and washing or flue gas desulfurization. Mechanical cleaning and washing removes only a portion of the coal's inorganic sulfur and none of it's organic sulfur. Since the coal is cleaned and washed prior to burning, it must be dried again before burning. The expense of washing and cleaning is not generally justified by the small reduction (40% at best) of total sulfur. In flue gas desulfurization, or "scrubbing", the sulfur oxide laden exhaust gases are brought into contact with a substance such as lime with which they can react and be removed from the gas stream. The various flue gas desulfurization schemes are distinguished from one another by use of wet or dry scrubbing agents and by single or multiple use of the scrubbing agent. Dry lime type scrubbers are recommended for all Cordova coal alternatives. Coal combustion forms nitrogen oxides by drawing nitrogen from both the coal and the air in which it burns. The amount of nitrogen oxide formed depends on flame temperature, amount of excess air in the flame, length of time combustion gases are maintained at elevated temperature and rate of quenching. High temperatures and excess air, foster nitrogen oxide production as does rapid cooling. New coal-fired boilers can be designed to minimize these emissions to produce release rates below regulatory requirements. STONE & WEBSTER A -18- There are four types of particulate control systems; mechanical collectors, electrostatic precipitators, wet scrubbers, and fabric filter baghouses. Mechanical collectors use gravity, inertia, or centrifagal force to separate the particles from the gas. Electrostatic precipitators operate by passing flue gases between high-voltage discharge electrodes and grounded collection plates, charging particles which are then collected and removed. Wet scrubbers use water to wash solid particles out of the gas stream, but are not widely used because they are expensive to install and operate. Fabric filter baghouses are the most effective of all control methods for small particles. However, the pressure drop involved in forcing the gas through fine filters increases operating costs and operating and maintenance problems are created by the high temperatures and corrosive chemicals typical in coal combustion gases. Recently, improved heat and chemical resistant filters have been developed which make this option more attractive to utilities. In view of the health hazards of small, respirable particles produced in coal combustion, it is likely that filter devices will see increased use in the future. Fabric filter pulse jet type collectors are recommended for all Cordova coal generation options. In addition to the various coal burning and air quality control systems, another variable in coal-fired plants is in the cooling system, which includes the condenser and the cooling tower. There are three types of steam condensers; direct contact jet condensers, surface condensers, and air-cooled condensers. Direct contact jet condensers spray externally cooled condensate directly into the steam turbine exhaust. In a surface condenser the turbine exhaust steam is separated from the cooling water, and the steam is condensed as it passes over tubes containing externally cooled circulating water. The turbine exhaust steam in the air-cooled condenser is passed through large banks of fin tube coils, where air is forced over coils which remove heat and condense the steam. The direct contact jet condenser and surface condenser require external cooling, while the air-cooled condenser does not require any additional cooling. Therefore, an air-cooled condenser is recommended for all coal generation options in Cordova. Cooling towers can either be wet or dry and combined with either forced draft or natural draft systems. The wet mechanical forced draft cooling tower is commonly used in conjunction with a surface condenser. Drawbacks of this system are the fogging and icing problems caused by the evaporation and atomization of the cooling water. There are no fogging and icing problems with dry cooling towers since they do not involve water evaporation and atomization. If the power plant can be licensed for a once-through cooling system, a surface condenser can use external cooling provided by a large adjacent body of water. However, since major environmental problems may be encountered with once-through cooling, a detailed investigation is required to determine the environmental impacts of such a system at a Cordova land-based power plant. STONE & WEBSTER A =110> 6.3.2 Environmental and Socioeconomic Issues (To be provided in the Final Phase I Report) 6.3.3 Siting, Conceptual Design and Capital Costs 6.3.3.1 Site Preparation The site selected for development of a coal-fired power plant is the area north of Cordova near Fleming Spit. This site was chosen for the following reasons: The Cordova region was within the tsunami zone of the 1964 earthquake. To protect the power station from a similar tsunami, the foundation should be located at least 32 feet above low tide. Elevated bed rock benches, at Fleming Spit, would provide protection from a tsunami and preferable foundation characteristcs. The site is adjacent to Orca Inlet which would simplify coal barge unloading. Major equipment components could also be easily unloaded and installed during the construction phase. The site's location away from residential areas would minimize environmental impact while the plant would still be close enough to Cordova to allow easy access by operating personnel. The site contains sufficient area for development of the coal-fired facility, and the City of Cordova already owns, or is in the process of obtaining, the land on which the plant would be sited. Four separate areas would have to be excavated in preparing the Fleming Spit site. First, the plant area must be blasted and graded to provide a level tier at the 50 foot elevation in the rock quarry. This would require excavation of approximately 46,000 cubic yards of rock. Next, the coal storage area must be excavated, diked and lined to contain coal pile water run-off. This second task includes approximately 3000 cubic yards of excavation and site fill, placement of 55,000 square feet of impervious liner, construction of 3000 cubic yards of gravel working surface, and 1200 cubic yards of random fill for dikes. Third, the ash disposal area must be excavated, diked and lined to contain the total 30-year plant ash discharge. It is estimated that this third task would require 65,000 cubic yards of excavation, 275,000 square feet of impervious liner, 30,000 cubic yards of dike fill, and 7500 cubic yards of protective rip rap. Finally, the coal dock and unloading facility will require approximately 44,000 square feet of steel sheet pile, 33,000 cubic yards of backfill, and an additional 580,000 cubic yards of rock for a breakwater. The rock-filled breakwater is expensive, but is necessary to ensure stability of barges during coal unloading. STONE & WEBSTER A -20- A0382042 TIDAL FLATS COAL UNLOADING DOCK SITE OCEAN BREAKWATER LEGEND ORCA INLET EXISTING FUTURE Figure 6.3-1 FLEMING SPIT COAL PLANT LAYOUT (CO1 OR CO3) STONE & WEBSTER a FUEL OIL. STORAGE TANK FLY ASH SILO ‘OM po , STORAGE AREA FABRIC FILTER CONDENSATE STORAGE TANK RAW WATER STORAGE TANK o TURBINE SWITCH- BUILDING | YARD PLANT CONVEYOR LIVE COAL STORAGE ORCA INLET UNLOADING CONVEYOR CLAM SHELL TYPE BARGE UNLOADER Figure 6.3-2 FLEMING SPIT COAL PLANT EQUIPMENT ARRANGEMENT (CO1 OR CO3) STONE & WEBSTER A © 5 ° o ° ° ¢ Figure 6.3-3 COAL PLANT PERSPECTIVE (CO1 OR CO3) A STONE & WEBSTER FUEL HEAT INPUT 163 mm BTU/HR 139,000 LB/HR Popo oo oo ooo MAIN STEAM FEEDWATER TURBINE GENERATOR N= 85% N= 95% 0% BLOWDOWN BOILER DUTY 135 mm BTU/HR DEAERATOR 1ST POINT BOILER \ 3RD POINT 4TH POINT | FEEDWATER FEED | | FEEDWATER 7 FEEDWATER / | HEATER PUMP | [HEATER 7 HEATER / 4 L Lu-y =f ee UNIT HEAT RATE = 13,600 BTU/KWHR Figure 6.3-4 COAL PLANT HEAT BALANCE (CO1) A0382059 GENERA- TION 13,333 KW 9 AUXILIARY POWER 1,333 KW ) CONDENSATE 5TH POINT PUMP | FEEDWATER | HEATER l | | | | | | | STONE & WEBSTER A 6.3.3.2 Coal Handling The coal handling system would consist of a series of belt conveyors and related equipment to unload, size, store, reclaim, and transfer coal. To obtain a satisfactory unloading rate for incoming coal the system would be designed for a maximum capacity of 150 tons-per-hour. The coal handling system would include a clamshell type unloader, conveyors, transfer house, and live storage building all of which would be enclosed because of heavy precipitation and periodic freezing. Both live and dead coal storage are provided at the site. Live storage would consist of a 25 foot high conical pile with a reclaim pit equipped with a vibrating drawdown hopper. No coal pushing machinery would be required for normal live storage reclaiming operations. Dead storage would be reserved for emergency use such as an interruption in coal deliveries, and would consist of an outside coal pile, highly compacted and sealed, located adjacent to the live storage building. Coal could be transferred between the live and dead storage piles with coal pushing machinery. 6.3.3.3 COl - Single 12 MW Unit Alternative C0Ol consists of a single 12 MW coal-fired steam electric generating unit constructed on land at the Fleming Spit site. The single unit concept is the least complex approach to providing 12 MW of power. The steam cycle of a single boiler and turbine generator eliminates multiple unit intertie complexities, but sacrifices a certain degree of reliability. A heat balance was prepared for alternative COl and is provided in Figure 6.3-4. This power plant would operate with a unit heat rate of 13,600 Btu/kWh at full electric generating load. Because of partial unit loading, over a 20 year energy supply period the unit heat rate would average approximately 14,400 Btu/kWh. The conceptual design of the single unit 12 MW coal-fired power plant was completed in sufficient detail to allow reasonably accurate cost estimates. Specifications for major plant components will be provided in the Final Phase I Report. This alternative would be placed in operation by January 1, 1986. It's present worth capital cost, including site preparation, coal handling and back-up diesel plant is $56,000,000. 6.3.3.4 C03 - Two 6 MW Units Alternative C03 consists of two 6 MW units constructed on land at the Fleming Spit site. The dual 6 MW unit concept has advantages in that systems common to both units can be intertied to support the overall plant operation in case of component failures. Each of the two units have a STONE & WEBSTER A -2l- single boiler with one turbine generator, one full capacity feedwater pump, one full capacity condensate pump, (an additional full capacity feedwater pump and condensate pump are provided for back-up, common to both units), five stages of feedwater heating, and an air-cooled condenser which are intertied to increase overall plant reliability. In addition to improved plant realiability, the dual 6 MW unit allows plant operation with better peak load efficiencies than is possible with a single 12 MW unit. Specifications for major components of a dual 6 MW unit coal-fired power will be provided in the Final Phase I Report. The dual coal-fired units would be placed in commercial operation on January 1, 1986, and have a present worth capital cost including site preparation, coal handling, and the emergency back-up diesel generator plant of $56,000,000. 6.3.3.5 CO4 - Two 6 MW Units With Fluidized Bed Boilers Alternative CO4 consists of two 6 MW units with atmospheric fluidized bed boilers constructed on land at the Fleming Spit site. Atmospheric fluidized bed boilers are commercially available in package units with the capacities required for a 6 MW unit and are a viable candidate for installation in Cordova. In addition, these boilers eliminate the necessity of costly flue gas desulfurization equipment that would be necessary for other coal generation options. The specifications for major components of a dual 6 MW unit coal-fired power plant with atmospheric fluidized bed boilers are essentially the same as those for alternative C03, the only differences being the boilers and emission control equipment. Alternative CO4 boilers and emission control equipment specifications will be provided in the Final Phase I Report. The CO4 dual coal-fired units with fluidized bed boilers would be placed in commercial operation on January 1, 1986. The present worth capital cost for alternative CO4, including site preparation, coal handling, and emergency back-up diesel generator plant is $48,000,000. 6.3.4 Fuel Supply and Costs At the present time the Usibelli mine near Healy, Alaska is the only operating coal mine in Alaska, although others are in early planning stages. By the summer of 1982, the Usibelli Coal Company expects to have coal unit trains in operation to a port facility near Seward. The coal would then be barged to Cordova. Usibelli coal has a heating value of approximately 8,000 Btu/lb and would cost: At the mine $22/ton RR transport to Seward 9/ton Barge loading at Seward 5/ton Barge to Cordova 21/ton Total $57/ton STONE & WEBSTER A =o0= These coal costs were used in the preliminary life cycle cost analysis for all coal generation alternatives. Further investigation of coal resources produced two additional potential coal supplies sources for Cordova. A discussion of optimized fuel costs is provided in Section 6.5.4. 6.3.5 Maintenance and Operation (To be provided in the Final Phase I Report) 6.3.6 Economic Analysis In preparing this economic analysis, the capital costs for coal generation alternatives C01, C03, and CO4 are considered expended by the end of 1985. These costs (in 1982 dollars) are: Coal-Fired Plant Back-Up Total Capital Cost Alternative with Auxiliaries Diesel Plant (Present Worth) col $57,020,000 $3,400,000 $54,000,000 Cco3 59,110,000 3,400,000 56,000,000 co4 51,130,000 3,400,000 48,000,000 In determining life cycle costs, review of comparably sized Alaskan coal-fired power plants indicates an assumed plant staff of 20 would be appropriate, together with operating and maintenance costs of 8.8 mils per kWh generated. Average salary for plant personnel, including benefits, was assumed to be $25 per hour. Using these above estimating parameters, total present worth life cycle costs for the land-based coal options are: col $180,000,000 C03 $175, 000,000 co4 $167,000,000 These alternatives are essentially equal within the accuracy of the estimates. 6.4 C02 - CORDOVA BARGE OPTION Alternative C02 consists of a single 12 MW coal-fired steam electric generating station mounted on a barge, with coal handling, coal storage, and ash disposal facilities constructed on land. Construction and assembly of the barge-mounted plant would be done outside of Alaska, and the plant would be transported by water to Cordova. Concurrently, site preparation work and construction of the coal handling and storage facilities would proceed at the Fleming Spit site, north of Cordova. On arrival, the barge-mounted plant would be placed on a filled foundation, and connected to the coal handling, water, sewer, and electrical systems. STONE & WEBSTER A 23s Tsunamis present a major risk to such a plant, and prohibitive expenses may be involved in providing adequate protection. However, to provide an initial estimate for comparison with other alternatives no attempt has been made to design or quantify such protection. The barge-mounted coal plant is very similar in conceptual design to alternative COl, the single 12 MW unit, land-mounted coal plant. The coal handling, coal storage, and ash disposal facilities are essentially identical and coal supply and costs are the same. Operating and maintenance costs, including plant personnel staffing are identical to COl. The emergency back-up diesel plant is common to all coal generation options. As with coal generation alternatives C01, C03, and CO4, the plant capital costs were assumed to be committed by the end of 1985. Capital costs for option C02, in 1982 dollars are: Barge-Mounted Plant Back-Up Total C02 Capital Cost Complete with Auxiliaries Diesel Plant Cost Present Worth $59, 300,000 $3,400,000 $56,000,000 The total present worth life cycle cost for the barge-mounted coal alternative is $182,000,000. This cost is not appreciably different from the nearly identical single land unit COl. It was anticipated that the barge-mounted plant would have significantly lower capital cost due to its construction outside of Alaska; however, this did not prove to be the case. Quotations were received from two independent manufacturers for the complete barge-mounted section of the power plant. In preparing those preliminary budgetary quotations, vendors generally use large allowances for indeterminants in estimating their costs. While pursuing’ the barge-mounted plant option to remove design uncertainties would undoubtedly reduce the capital cost estimates, it is doubtful that the barge-mounted plant could gain a decided advantage over other coal options. Even if capital costs were reduced $10,000,000, a reasonable goal, costs of the barge-mounted option would remain in the same range as other coal alternatives. Because of the high risk associated with lack of tsunami protection and the lack of competitive edge provided by a barge mounted plant, this alternative should not be pursued as a viable coal option. 6.5 OPTIMIZED COAL GENERATION The five coal generation alternatives evaluated for Cordova, are essentially economically equal. Option C05, the Bering River coal field mine-mouth plant near Katalla, was eliminated from further consideration due to uncertainties in the development of the coal mine. Of the remaining STONE & WEBSTER A -24- four options, one was selected for further optimization to provide a representative coal generation plant for comparison with the other study alternatives. Option COl, the single 12MW land-based unit, is less reliable than a dual unit plant and in the early years of the study period would be operating almost exclusively at low generating capacity with resultant inefficient fuel consumption. The barge-mounted single 12MW unit, option C02, has the same disadvantages as COl plus the uncertainties involved in the barge-mounted portion of the plant. Option CO4, the dual 6MW units with fluidized bed boilers, has the primary advantage of negating the requirement for a flue gas desulfurization system. However, calculations show, that even in a conventional plant, flue gas desulfurization (FGD) would not be necessary to meet federal regulations until 1998, thus removing the advantage of fluidized bed boilers. Therefore, option C03, the dual 6MW units installed near Fleming Spit, was chosen for this optimization due to its reliability, conventional design, and intermediate load efficiencies. The detailed investigation of coal generation alternative CO3 is reported in detail in this section. 6.5.1 Technical Analysis and System Description The optimized plant includes two conventional 6MW coal-fired steam electric generating units as described in Section 6.3.1. 6.5.2 Environmental and Socioeconomic Issues No "fatal flaw" environmental or socioeconomic factors have been determined to exist for coal-fired generation. These issues will be fully developed in the Final Phase I report. 6.5.3 Siting, Conceptual Design, and Capital Costs Site preparation requirements are discussed in Section 6.3.3.1. The coal-fired plant will be located on elevated bedrock tiers just north of Flemming Spit. This provides tsunami protection and improved foundation characteristics. The optimum plant layout is shown in Figures 6.3-1 and 6.3-2. Since overall site preparation costs at Fleming Spit contribute significantly to the capital expenditure for the entire facility, a sensitivity analysis was performed to evaluate the effects of this site preparation on life cycle costs. This was accomplished by substituting Significantly smaller site preparation costs in an otherwise-identical life eycle cost analysis for a coal-fired plant. Results of this analysis, in comparison with the other study alternatives, will indicate whether to pursue a less complex plant site, or to further optimize the civil earthwork design at Fleming Spit. The results of this site preparation sensitivity analysis are provided in Table 6.5-1 and in Section 6.5.6. STONE & WEBSTER A -25- The major components of the two 6MW units are the same as described in Section 6.3.3.4, except that the dry line scrubbers (flue gas desulfurization) will not be installed in the initial plant construction. Calculations show that the FGD system will not be necessary to meet environmental regulations until 2002, (using Usibelli coal) and 1998 using Canadian coal. Thus, it is assumed that the scrubbers will be added to the coal-fired plant just prior to their first required use, see Table 6.5-1l. A second sensitivity analysis was performed to investigate the effects of the lower electrical demands which result from a scenario with no-space heating. Dual 5MW units were considered suitable to meet these lowered power requirements. No flue gas desulfurization would be required at this smaller plant during the study period, further reducing costs. Capital costs for dual 5MW units are shown in Table 6.5-1. 6.5.4 Fuel Supply and Costs During the optimization phase, two other potential Canadian coal sources were identified in addition to the Usibelli mine near Healy, Alaska. These added sources and their respective costs are: B.C. Coal, International could supply coal to a port at Roberts Bank, British Columbia for transport by barge to Cordova. The fuel is Grain Hills Thermal Coal with a heating value of 11,000 Btu/lb, and would cost: Loaded on barge at Roberts Bank $50/ton Barge to Cordova $15/ton Total $65/ton Essel Resources, Canada could supply coal to Vancouver, British Columbia, for barging to Cordova. This coal is from the Byron Creek mine with a heating value of 11,000 Btu/lb and would also have an approximate cost of $65/ton. Further investigation permitted refinement of barging costs for Usibelli coal, resulting in the following reduced costs: Cost at the mine $22/ton RR transport to Seward $ 9/ton Loading Barge at Seward $ 5/ton Barge to Cordova $14/ton Total $50/ton The coal costs noted above were used in analyzing the life cycle cost of optimized coal generation alternative. The results of this analysis are provided in Section 6.5.6. STONE & WEBSTER a -26- 6.5.5 Maintenance and Operation (To be provided in the Final Phase I Report) 6.5.6 Economic Analysis Estimated capital expenditures for the optimized coal alternative, with associated sensitivity analyses, are shown in Table 6.5-1. Further investigation of miscellaneous operating and maintenance expenses resulted in an increase from 8.8 mils to 10 mils/kWh generated for the dual unit coal-fired plant. Plant availability is assumed to be 96 percent. The following summarizes present worth life cycle costs for coal generation: PRESENT WORTH LIFE CYCLE COSTS Predicted Site Minimal Site Preparation Preparation Two 6MW Units w/Healy coal $168, 100,000 $139, 400,000 Two 6MW Units w/Canadian coal $166,700,000 $138,100,000 Two 5MW Units w/Healy coal $142,700,000 $117,500,000 Two 5MW Units w/Canadian coal $140,900,000 $115,700,000 STONE & WEBSTER A -27- SCENARIO Two 6MW Coal-Fired Units Healy Coal Two 6MW Coal-Fired Units Canadian Coal Two 5MW Coal-Fired Units TABLE 6.5-1 OPTIMIZED COAL GENERATION CAPITAL EXPENDITURE SCHEDULE ITEM YEAR Back-up Diesel 1985 Power Plant 1986 Site preparation 1986 *Limited Site 1986 FGD system 2002 CAPITAL EXPENDITURE (1982 $) $ 3,400,000 $31, 300,000 $26,700,000 $ 2,200,000 $ 5,780,000 TOTAL CAPITAL COST PRESENT WORTH With predicted site preparation *With minimal site preparation Back-up Diesel 1985 Power Plant 1986 Site Preparation 1986 *Limited Site 1986 FGD system 1998 $ 3,400,000 $31, 300,000 $26,700,000 $ 2,200,000 $ 5,780,000 TOTAL CAPITAL COST PRESENT WORTH With predicted site preparation *With minimal site preparation Back-up Diesel 1985 Power Plant 1986 Site preparation 1986 *Limited Site 1986 $ 3,400,000 $27,500,000 $23,500,000 $ 1,900,000 TOTAL CAPITAL COST PRESENT WORTH With predicted site preparation *With minimal site preparation CAPITAL COST PRESENT WORTH $ 3,000,000 $27,000,000 $23,000,000 $ 1,900,000 $ 3,100,000 $56,100,000 $35,000,000 $ 3,000,000 $27,000,000 $23,000,000 $ 1,900,000 $ 3,500,000 $56,500,000 $35,400,000 $ 3,000,000 $23,700,000 $20, 300,000 $ 1,600,000 $47,000,000 $28, 300,000 STONE & WEBSTER A 7. HYDROELECTRIC GENERATION All hydraulic investigations in this study are based on a preliminary field reconnaissance and review of existing literature. This level of analysis is adequate to determine potential suitability of sites, power generating capacity and the relative cost of development. To accomplish this analysis, the following were studied for each site: streamflow, tailwater effect, reservoir area and capacity curves, topography, site geology, and environmental, socioeconomic, archeological and historical considerations. The information obtained in these studies permitted development of a preliminary layout, calculation of hydroelectric power capacity, and development of a capital cost estimate for each viable alternative. 7.1 METHODOLOGY AND PARAMETERS 7.1.1 Stream Flow For each watershed considered for hydroelectric development, an estimate was prepared to determine the total quantity of stream flow available, and the annual variance of that flow. Observed stream flow data is normally obtained from the publications of the U.S. Geological Survey, operations records of other regional hydroelectric Plants, the Corps of Engineers, and other sources. For this study, the availability of stream flow data was limited to the following four gaging stations: STATION NO. LOCATION 15216000 Power Creek 15216100 Humpback Creek 15219000 West Fork Olsen Bay Creek 15226000 Solomon Gulch Several other temporary gaging stations have also been established in the area but these have limited or discrete records. Due to the location of these gaging stations and the wide range of precipitation in the study region, standard regression techniques were generally employed to estimate stream flows. The Juneau office of the U.S.D.A. Forest Service was contacted to obtain the latest revision of the R-10 Water Resources Atlas, scheduled for printing in March 1982 for use in stream flow estimates in the Chugach National Forest. The R-l10 Water Resources Atlas presents stream flow STONE & WEBSTER A -28- equations developed through the step-wise multiple linear regression process in which physical watershed characteristics and precipitation estimates are regressed against calculated streamflow characteristics for U.S. Geological Survey (USGS) gaged watersheds. These equations are considered suitable for water resource inventories, project evaluation and planning, and preliminary project design. 7.1.2 Tailwater Effect In hydroelectric design, tailwater curves provide water levels immediately downstream from the proposed dam, along the penstock and at’ the powerhouse. These water levels may be determined by backwater computations or by actual measurements taken at the site (high water marks). For the alternatives investigated in this study, tailwater curves have not been developed. However, estimated tailwater effects have been taken into account when locating proposed hydroelectric structures. In general, the hydroelectric sites under consideration would not create a significant change in natural stream water levels. These streams are naturally subject to a wide flow variation. Typically, there is a very steep section of the stream or a series of falls located downstream from the proposed dam site which reduces the tailwater effect. Penstocks have been located above the natural streambed, and powerhouses have been sited to minimize downstream degradation. Some alternatives were analyzed with powerhouses located near sea level. Locations of these powerhouses were based upon the effect of high mean tide and the potential impact of a tsunami. In addition, siting was predicated on minimizing the downstream degradation of spawning beds. 7.1.3 Reservoir Area and Capacity Curves Reservoir area and capacity curves were developed for each project, with dams located based upon the topography of the site. Impoundments were developed to provide the amount of water required for maximum firm power generation and to provide adequate storage of water for low flow years. 7.1.4 Topography At a project site the topographic relief and dam height determines the distance which the water may fall. The greater the fall, the higher the potential power generation. Each identified site was established to permit development of the maximum site "head" or fall. STONE & WEBSTER A a 7.1.5 Regional Geology of the Study Area The following description is based on several regional studies and is of a general nature due to the limited information published on the subject and lack of definitive field investigations. ae Geomorphology The study area is characterized by active glaciation and associated landforms. Due to the dynamic tectonic environment and active glaciation the area is undergoing regional uplift, local rapid downcutting by streams, local slope instability in the form of major landslides, local rockfalls, local debris flows and avalanches in areas of major snow accumulation. The coastline is characterized by a sequence of northeast trending major fjords; deep, long, narrow, steep-sided valleys formed by glacial processes. Perpendicular to the trend of these fjords are a more weakly developed set of topographic lows, northwest trending valleys including Jack Bay, Sawmill Bay, Silver Lake, Galena Bay, Two Moon Bay and Eyak Lake. These gross regional geomorphic trends are probably related to regional fracture patterns and major structural features resulting from the tectonic history of the area. b. Stratigraphy The rocks in the study area have been divided into two groups. These are the Valdez Group and the Orca Group. The division is based on slight variations in metamorphic facies and lithology. The Valdez Group rocks cover the general study area from Valdez south to Port Fidalgo and the Orca Group extend from Port Fidalgo to south of Cordova beyond the southern limit of the study area. The Valdez Group is a metamorphsed sedimentary series including bluish-gray and dark gray quartzites, graywackes, arkoses and quartz-schists interbedded with generally thin beds of dark blue or black slate, shale, mica-schist and occasionally some conglomerate. The Orca Group exhibits a slightly lower grade of metamorphism then the Valdez Group and consists of thick bedded brown and gray sandstones, black limestones, arkoses with thin zones of slate and occasional conglomerate greenstones associated with highly mafic basalt flows. The rocks in both the Valdez and Orca groups are highly deformed and fractured. Extensive secondary quartz emplacement has occurred along the fractures. The thickness of these quartz veins ranges from a fraction of an inch to several feet. ec. Structure The structural geology of the area is characterized by highly deformed rocks, tightly folded and faulted along two dominant STONE & WEBSTER A structural orientations; northwest and northeast. These structural features result from the active subduction of the Pacific plate which is occurring along the southern coast of Alaska and extending westward along the Aleutian Island arc. Numerous thrust faults have been inferred in the study area, the largest is named the Contact Fault. Other smaller thrust faults include the Jack Bay Fault, Landlocked Bay Thrust and Galena Bay Thrust. Many other folds and faults trending predominantly northwest and northeast have been inferred from aerial photographs and satellite imagery. 7.1.6 Environmental, Socioeconomic, Archeological and Historical Considerations No environmental "fatal flaws" have been established for any hydroelectric alternative. However, the following specific areas have been identified as requiring further field investigation, study and consideration prior to final design and implementation of any hydroelectric alternative. a. Fish and Marine Invertebrates The Lakes, rivers, and streams in the region support populations of anadromous and resident fish, and the habitat, free passage and spawning of these fish must be studied to assure that this resource will not be adversely impacted. b. Wildlife The areas surrounding the lakes, rivers, and streams support a wide variety of mammals and birds and in particular the banks of the water body provide a source of food and habitat. These resources must be inventoried and studied to assure minimum impact during construction and plant operations. ec. Land and Vegetation Tree clearing and vegetation removal will be required for the construction of roads, buildings, penstocks, dams and spillways. Existing vegetation will also be inundated when the water level is raised, causing both root rot and physical inundation. Due to operations of the reservoir, some acreage of land will be prematurely lost due to inundation. Land use and vegetation will change and impacts should be identified and addressed. 7.1.7 Conceptual Design and Alalysis Parameters The assessment of hydroelectric sites was based upon three major considerations: Power Generation Capacity Risks and Fatal Flaws Economics STONE & WEBSTER a -31- As a basis for analysis, the demand forecasts developed in Chapter 4 of this study indicate that for a hydroelectric development to meet the energy requirements of the City of Cordova, it must have an annual energy capacity exceeding 50,000 MWh with a peaking capacity of 12 MW, and that such sites should be capable of a year-round minimum installed generating capacity of 3 MW. Assessment of geologic and environmental risks was predicated on the following considerations: a. Potential Geologic Hazards Consideration was given to possible geologic hazards resulting from seismic, tectonic and geotechnical aspects of the region from Cordova to Valdez. Geologic hazards identified in this area included: potential earthquakes, active faults, rugged topography, landslides, avalanches, active glaciers, tsunamis, low strength and low durability rocks of the Valdez and Orca _ Groups, sedimentation behind water impounding structures and foundation problems associated with frozen soil or rack masses. The area under consideration falls into seismic zone 4 as designated by the Uniform Building Code. Many large earthquakes have affected the study area which have exceeded eight on the Modified Mercali Intensity scale. The reason that this region is seismically active is that it is located at the boundary of two major lithospheric plates and subduction of one of these plates is actively occurring at the present time. The largest known event to affect the study area is the Prince William Sound earthquake which occurred in 1964. This event had a magnitude of 8.5 on the Richter scale and its epicenter was located 67 miles northeast of Cordova. Surface rupture associated with this event resulted in 6 feet of vertical uplift and 40 feet of lateral displacement along the coast near Cordova. There are many active faults in the study area, the largest system is the Contact fault located mid-way between Cordova and Valdez. Some of these faults have undergone significant displacements associated with seismic events during historic time. The study area has a large percentage of very rough topography characterized by active alpine glaciation and associated geomorphic landforms. Total vertical relief is 5000 - 6000 feet. The steep slopes associated with this rugged topography and active downcutting by major streams leads to many areas of slope instability. Rock falls, landslides, debris flows and other forms of mass earth movements are common in many parts of the study area. In addition, avalanches are also prevalent in many areas with steep slopes and significant snowfall. Several glaciers also exist within the study area. These include the Allen, Woodworth, Schwan, Heney and Sheritan glaciers all of which are active at the present time. STONE & WEBSTER XR -32- The effect of tsunamis was considered at those sites within the predicted wave runup. The wave runup near Cordova resulting from the 1964 seismic event was 16 feet above high tide and 32 feet above low tide. A more detailed evaluation of the maximum runup would be required before a coastal site is developed. The potential problems associated with the low strength and low durability of the rocks in the Valdez Formation include poor construction material sources, slope instability, low foundation bearing capacity, potential for slaking and freeze-thaw deterioration in tunnels, excavations and cut’ slopes. These problems are not insurmountable with good engineering practices, but their solutions will generally increase the cost of construction. Sedimentation behind water retention structures may result from normal stream sediment load, mass wasting from steep canyon slopes and avalanche debris. The potential volume of material from these three mechanisms could be quite large, requiring removal of significant amounts of material from behind water impounding structures. b. Environmental, Socioeconomic, Archeological and Historical Consideration was given to anadromous and resident fish, and marine invertebrates, wildlife, vegitation, land use, socioeconomic, and archeological and historical sites. Federal, State and local agencies have been contacted and each has identified some conserns which must be studied and addressed. While no "fatal flaws" were disclosed, the major risk identified is the anadromous and resident fish and wildlife. Finally, estimates of construction, operations and maintenance costs, including cost of a back-up energy source were prepared based upon the preliminary conceptual design of the hydroelectric plant structures. Using these cost estimates as a basis, a project life cycle analysis was developed and the projects present worth was calculated. 7.2 POWER CREEK (HO1) 7.2.1 Technical Analysis and System Description 7.2.1.1 Location and Description Power Creek is situated in the Chugach mountains along the northern shore of the Gulf of Alaska. The creek originates at the Shepard Glacier about 13 miles northeast of Cordova, and flows through a steep walled valley to Eyak Lake. Located on the southeast side of Mount Kelly and Snyder Mountain, it has a drainage area of approximately 20.5 sq mi. STONE & WEBSTER A -33- Four to five miles of Power Creek flows through a U-shaped glacial valley approximately one-quarter mile in width. A large fan shaped ridge about 300 to 400 feet in height, resulting from an ancient landslide bisects the lower end of this valley. The creek circles around the eastern side of this fan through a narrow gorge and over Ohman Falls where it falls about 175 ft in a horizontal distance of approximately 500 ft. Downstream of Ohman Falls, the creek falls about 200 ft in 1 1/2 miles to Eyak Lake. Figure 7.2-1 shows Power Creek's topography and profile. 7.2.1.2 History and Background Turn-of-the-century investigators identified Power Creek as the best stream within the vicinity of Cordova for hydroelectric development. These investigations indicated that the creek could be diverted above Ohman Falls through a tunnel to a powerhouse upstream of Eyak Lake. By 1913 about 60 ft. of 4 by 6 ft. tunnel had been driven but was abandoned due to construction difficulties. In 1951, the tunnel portal could not be found and apparently had collapsed. More recently hydroelectric development studies for Power Creek have been made both by the Corps of Engineers and private consultants. These studies have identified potential dam sites, tunnel and penstock routes, and powerhouse locations. A list of these studies is provided in the bibliography. The Corps of Engineers has conducted on-site geological and geotechnical investigations and has eliminated the possibility of developing a large storage dam above Ohman Falls capable of regulating Power Creek. This limits hydroelectric development to a "run-of-river" project. 7.2.1.3 “Run-of-River" Hydroelectric Development In a "run-of-river" hydroelectric project, the water is diverted from the stream by the small dam or diversion structure into a conduit which leads to a powerhouse where it is used for power generation and returned to the stream. The smaller the dam, the smaller the water storage, reducing the amount of firm power that can be generated during periods of low stream flows. Power Creek has a summer-fall peak and winter-spring low. During a dry year, water may not be available to meet energy demands, while during a wet year there may be a surplus of energy. 7.2.1.4 Hydrology Gage station 15216000 was established on Power Creek about 1 1/2 miles downstream of Ohman Falls in July 1913. Intermittent stream flow records are available between 1913 and 1947, with continuous records from 1947 to date. STONE & WEBSTER A a3i= Table 7.2-l1 represents the Power Creek annual mean stream flow and ranking for the water years 1948-1980. Figure 7.2-2 is the annual flow duration curve. Typically, average stream flows vary from a low of 34 cfs in March to a high flow of 490 cfs in July. The average annual stream flow is 247 efs. Typical flows during late winter and early spring are less than 40 efs, which would limit the amount of power generated during this period. The 1915 USGS Water-Supply Paper on Power Creek highlighted a problem concerning underground flow: "The discharge at the proposed point of diversion for power development, which is about 1 1/2 miles above the gage, was about 25 percent less than at the regular measuring section on September 10, 1913, as determined by measurement. The actual difference in run-off at the two sections was probably somewhat less, as the bed of the creek at the upper section appeared to be more porous, thus affording a greater opportunity for underground flow." The site of the diversion is the location identified by the Corps of Engineers for a run-of-river dam. This would suggest that the gaging station stream flow readings may overstate the amount of water available for power generation. The porous nature of the site soils was documented by the Corps of Engineers during their 1980 investigations at Ohman Falls. Analysis of Power Creek hydrology suggests that sufficient water would be available only 8 months per year. 7.2.1.4 Geology Following is a brief description of the geology of Power Creek. A more detailed and site specific description will be provided in the Final Phase I Report. a. Geormorphology The geomorphology of the Power Creek site is characterized by glacial landforms combined with an active stream channel. Power Creek follows a major northeast trending V-shaped glacial valley which parallels the predominant topographic trend in the region. The upper valley has very steep slopes disected by hanging valleys and steep erosional gullies. An ancient landslide mass forms a large fan-like ridge at Ohman Falls. This landslide dammed Power Creek forming a large lake upstream of Ohman Falls. Glacial processes produced rapid infilling of this lake with silt, sand and gravel until the natural dam was breached and the recent valley was cut to the present configuration of Power Creek. STONE & WEBSTER A -35- b. Stratigraphy The bedrock at the Power Creek site is part of the Orea Group which characterize a large area surrounding the site. The lithologies within the Orca Group make up a suite of slightly metamorphosed sedimentary rocks including sandstone, limestone, arkose, graywacke and thin slate, shale and conglomerate. In addition, greenstones associated with basic basalt flows, are found within the Orca Group. ec. Structure and Techtonics Regional studies of geologic structure indicate that the Power Creek site lies within an area that is intensely deformed exhibiting many tight folds and associated faults which have shallow dips to the northeast and trend roughly northwest. Several faults have been inferred in the general vicinity of the Power Creek site using aerial photographs. One of these follows the course of Power Creek and dips to the northwest. d. Engineering Geology The type of material and the stability of the ancient landslide mass at Ohman Falls are of considerable concern in development of a hydroelectric generating facility at Power’ Creek. Several investigations have been conducted to determine if the mass is still moving. Seismic refraction surveys conducted in 1981, indicated that the landslide mass consisted of relatively low velocity materials, producing minimal compressional waves. In 1913 a tunnel was driven into the landslide mass about 200 ft. west of Ohman Falls at elevation 430. The tunnel generated very soft sedimentary rocks which disintegrated upon exposure to air, and required timber shoring to keep it open despite its shallow depth. The absence of surface drainage within the landslide area indicates that this mass is highly permeable. Observations indicated that there are no permanent streamflows across the mass and that none of the larger depressions, which reach a maximum depth of 100 ft., contain water. Also noted were numerous springs and seeps downstream of Ohman Falls at elevation 350. The landslide mass probably consists of broken and jumbled fragments of the original sedimentary rocks typiical of the area. They are now weak, highly permeable and in a stable configuration. The southeast valley wall at Ohman Falls consists of bedrock close to the ground surface. Snow avalanches occur frequently on these slopes during the winter months, with snow depths of 70 feet recorded at the end of June. The southeast valley wall is blanketed with colluvium deposited by rock falls or avalanches, and ice jacking perpetuates the rockfalls on the southeast valley wall. STONE & WEBSTER A Power Creek carries a considerable sediment load, which is derived from several sources including stream channel erosion, mass wasting into the channel from steep adjacent slopes, and glacial and avalanche debris. A conservative estimate of the total annual sediment load in Power Creek is 4.1 to 6.2 acre-ft. per year. 7.2.1.5 Hydroelectric Structures Hydroelectric development proposed for Power Creek uses a 35 ft high diversion dam above Ohman Falls. Water would be transported by a 5000 - 6000 ft tunnel or penstock, approximately 8 ft in diameter to a powerhouse where the water would be returned to Power Creek. A road to provide access to the dam powerhouse would be constructed from the end of the existing road above the USGS water gaging station over the fan-like ridge at Ohman Falls. The powerhouse would contain two Francis turbine units of approximately 2.5 MW capacity. A transmission line would be constructed between the powerhouse and a substation at Cordova. 7.2.2 Fatal Flaw Analysis and Conclusions 7.2.2.1 General A review of reports and studies previously prepared for Power Creek identified several areas that will impact on the operations of a hydroelectric project. These are: Sedimentation Avalanches Hydrology Power Generation 7.2.2.2 Sedimentation Power Creek is a glacially fed stream which carries a relatively high concentration of suspended sediment and bed load. USGS has taken suspended sediment samples using a depth-intergrating sampler. The USGS data has been plotted on Figure 7.2-3, scatter diagram, with the linear regression function developed to express the relationship between stream flow and tons of suspended sediment. The Camp turbulent flow model has been used to predict an average amount of sediment per year of between 3500 and 5400 tons. During high stream flow years the amount trapped could be as high as two or three times that estimate. The sediment has been assumed to be comprised of 10 percent clay, 33 percent silt, and 57 percent sand. This composition has a weight of 81 lbs/cu ft. Based on this density, 3200 - 5000 cu yd of sediment would collect in the small reservoir annually. This is more than 10 percent of the reservoir storage capacity. Annual or bi-annual removal of the sediment will be required to protect the hydraulic equipment and prevent blockage of the tunnel or penstock. SroMe ai Wenarin -37- a 7.2.2.3 Avalanches As shown on Figure 7.2-4, the proposed run-of-river dam site is located near several avalanche paths. A detailed description will be presented in the Final Phase I Report. Since the proposed water retaining structure would be of mass concrete, the impact of an avalanche would not affect its structural integrity. The depth of snow build-up in the gorge at the dam site has been measured at 70 ft in late June. Since the proposed dam is only 35 ft high, it may be inaccessible until mid-summer, limiting the project to seasonal operation. 7.2.2.4 Hydrology Due to avalanches and lack of stream flow, the "run-of-river" hydroelectric facility would probably be shut down each year from December to May. Depending upon the amount of snow accumulation at the dam site, removal of accumulated sediment may not be possible until July, precluding power generation until mid-summer. Construction of a sedimentation sluiceway at the dam would not be feasible because the resulting high concentration of sediment released over a short period of time may affect downstream spawning beds and the fish resources. 7.2.2.5 Power Generation Due to seasonal low flows, avalanche and sedimentation problems, a run-of-river hydroelectric development on Power Creek would not meet Cordova's year-round energy needs. At best, Power Creek could generate electricity from May through December. Table 7.2-2 shows the probable monthly amounts of power which could be produced. 7.2.2.6 Conclusion Power Creek cannot meet the year-round energy needs of the City of Cordova. The available power from a run-of-river development will vary depending upon stream flows because a diversion dam cannot be constructed to provide storage capacity. Additionally, risks to structures and equipment from sedimentation will require annual or bi-annual sediment removal, while the build-up of snow from avalanche and normal precipitation can be expected to hamper or prevent plant operation, for approximately 4-5 months per year. Because of its lack of reliable year-round power and the combination of a number of "high risk" technical problems, Power Creek is not recommended for further consideration. STONE & WEBSTER A TABLE 7.2-1 POWER CREEK ANNUAL (cfs) AVERAGE STREAM FLOWS ANNUAL MEAN VALUE AND RANKING ANNUAL MEAN VALUE AND RANKING IN YEAR ENDING MARCH 31 IN YEAR ENDING SEPTEMBER 30 1949 266.00 26 1948 274.0 7 1950 264.00 25 1949 247.0 16 1951 208.00 4 1950 263.0 12 1952 256.00 22 LO5u: 231.0 23 1953 283.00 28 1952 245.0 18 1954 263.00 24 1953 300.0 3 1955 253.00 21 1954 233.0 22 1956 200.00 3 1955 246.0 17 TOS i, 242.00 17 1956 220.0 26 1958 296.00 30 1957 260.0 13 1959 294.00 29 1958 82150 || 2 1960 223.00 8 1959 219.0 27 1961 262.00 23 1960 264.0 10 1962 252.00 20 1961 259.0 14 1963 227.00 11 1962 205.0 30 1964 227.00 12 1963 250.0 15 1965 228.00 13 1964 223.0 25 1966 224.00 9 1965 236.0 19 1967 251.00 18 1966 255 <0 ex 1968 278.00 27 1967 265.0 8 1969 196.00 2 1968 228.0 24 1970 238.00 15 1969 181.0 32 1971 240.00 16 1970 288.0 5 1972 222.00 6 1971 236.0 20 1973 221.00 5 1972 211.0 28 1974 174.00 1 1973 195.0 31 1975 229.00 14 1974 180.0 33 1976 223.00 7 L975 263.0 11 1977 395.00 32 1976 292.0 4 1978 251.00 19 1977 336.0 1 1979 227.00 10 1978 210.0 29 1980 297.00 31 1979 264.0 9 1980 284.0 6 Average Stream Flow (1949-1980) = 247 cfs STONE & WEBSTER A NOTE: MONTH January February March April May June July August September October November December TABLE 7.2-2 POWER CREEK RANGE OF AVAILABLE HYDROELECTRIC CAPACITY 25% TIME CAPACITY AVAILABLE EXCEEDS (kW) 1,300 1,200 1,000 1,300 5,500 10,300 12,500 11,100 12,100 7,600 3,900 1,800 95% TIME CAPACITY 500 400 300 400 800 5,000 7,000 5,000 3,000 2,000 1,000 700 The availability of hydroelectric generation from this site during January, February, March and April is uncertain due to avalanche and sedimentation. AVAILABLE EXCEEDS (kW) STONE & WEBSTER A ftozszos OHMAN FALLS PROFILE US@S @AGING STATION FOOTBRIDGE FOREST Figure 7.2-1 POWER CREEK (HO1) TOPOGRAPHY AND PROFILE veéozszov n w 2 = ° a uw = 4 w oc E n 40 50 60 PERCENT EXCEEDENCE NOTE: MONTHLY FLOW DURATION CURVES WILL BE PROVIDED IN THE FINAL PHASE | REPORT. Figure 7.2-2 POWER CREEK (HO1) ANNUAL FLOW DURATION CURVE STONE & WEBSTER A STREAM FLOW (CUBIC FEET PER SECOND) 0.1 Os 1 NOTE: SEE APPENDIX B TABLE 1 FOR FLOW AND SEDIMENT DATA Figure 7.2-3 POWER CREEK (HO1) ———t—ttitiiit 5 10 SUSPENDED SEDIMENT DISCHARGE (TONS PER DAY) SUSPENDED SEDIMENT DISCHARGE STONE & WEBSTER A0382073 Le s \ V Ns : Z S Be. \ WS e080 ES : Cel = 2 se Y a D RS S, Ze == ss 00 y/ “SAN + gi od > SA nO 600 Z Reso 6 U SY, _ FALLS LEGEND DAM RESERVOIR ROAD PENSTOCK AVALANCHE PATHS CHUGACH NATIONAL FOREST Figure 7.2-4 POWER CREEK (HO1) AVALANCHE PATHS 7.3 SILVER LAKE 7.3.1 Technical Analysis and System Description 7.3.1.1 Location and Description Silver Lake is located about 15 miles southwest of Valdez near Galena Bay on the Valdez Arm of Prince William Sound. The lake is situated in the bottom of a bowl surrounded by mountains on three sides. Streams which feed the lake originate at the Silver Glacier and other small unnamed glaciers. This lake is 3.0 miles in length with a maximum width of 0.7 miles. It's surface area is approximately 978 acres at water surface elevation 306 and the maximum observed depth is approximately 278 ft. The total drainage basin is approximately 24.5 sq mi. Silver Lake discharges into the Duck River through a narrow gorge and falls about 306 ft in about 1 1/2 miles to the lagoon on Galena Bay. Duck River has four sets of falls greater than 10 ft in height with the largest approximately 60 ft in height. Figure 7.3-1 shows Silver Lake and Duck River topography and profiles. 7.3.1.2 History and Background In 1915 the U.S.G.S. identified Duck River and Silver Lake as the most favorable opportunity for water power development in the Prince William Sound Region. They noted that the geology and topography at the outlet of the lake was suitable for the construction of a dam of a height of 100 ft or more. The Corps of Engineers conducted a brief power assessment of Silver Lake in 1980 but has not conducted any detailed studies of the site. 7.3.1.3 Hydrology On May 13, 1913 a temporary gaging station was established on the Duck River, about 600 ft upstream from the Lagoon. Gage readings were made at intervals of four or five days through December 1913. No other stream flow records are available. Figure 7.3-2 is a hydrograph prepared by the U.S.G.S. for the period May through December, 1913. This confirms that stream flows are very low in the late winter and early spring, with a minimum flow of 30 cfs. Due to the limited availability of stream flow data, regression analysis was employed based on an average annual flow of 200 cfs. This probably understates the flow available for generation, based on the existing U.S.G.S. data and a limited correlation of Duck River data with the long historical stream flow record at Power Creek. STONE & WEBSTER A -39- 7.3.1.3 Geology The bedrock at Silver Lake is mapped as part of the Valdez Group, a slightly metamorphosed sedimentary sequence consisting of graywacke, quartzite, arkose, quartz-schist and some thin beds of slate, shale, conglomerate and mica-schist. Secondary quartz has been emplaced along fractures in these rocks, the quartz ranges from a fraction of an inch to several feet thick. The rocks in this area are highly deformed, intensely folded and faulted in the general area of Silver Lake. No detailed geologic map is presently available in the Silver Lake area. The Galena Bay Thrust, a major thrust fault, trends northwest roughly parallel to Silver Lake passing along the northeastern shore of the Lagoon. Other faults have been inferred near Silver Lake from aerial photographs, and trend parallel to Silver Lake, with one extending northwestward from the northwest corner of the lake. 7.3.1.4 Power Operation Due to the lack of flow data at Silver Lake it was necessary to correlate flow data with the gaging station at Power Creek in order to determine the critical low flow period. As summarized on Table 7.3-1, this correlation established the spill or depletion from storage as a percentage of the average annual flow. If the percentage is positive, there is spill. If the percentage is negative, there is a depletion from storage. Based upon the critical low flow years from 1962 through 1974 approximately 160,000 acre-ft of storage would be required to maintain an average annual stream flow of 200 cfs. Therefore, to develop the power resource at Silver Lake, the reservoir must be totally regulated, and the amount of storage provided must be able to maintain the annual average stream flow during low flow years. Normal maximum operating surface elevation of Silver Lake is 410 ft with an average annual flow of 200 cfs. Based upon the average annual discharge of 237.5 cfs suggested in the "Reconnaissance Study of Energy Requirements and Alternatives for Cordova", a reservoir storage of approximately 200,000 acre-ft is required with a maximum operating surface elevation of 450. 7.3.1.5 Power The proposed Silver Lake reservoir would be fully regulated. Two powerhouse locations have been considered: one at tide water and the second located on Duck River at elevation 65. Two dam heights have been investigated to provide required storage to meet critical low flow periods. STONE & WEBSTER A -40- ae Case l Maximum operating reservoir water surface elevation 410 Powerhouse located at tidewater Average annual discharge 200 cfs Estimated power capacity - 5100 kW Estimated firm annual energy - 45,000 MW/hrs b. Case la Maximum operating reservoir water surface elevation 410 Powerhouse located on Duck River at elevation 65 Average annual discharge 200 cfs Estimated power capacity - 4200 kW Estimated firm annual energy - 36,800 MW/hrs ec. Case 2 Maximum operating reservoir water surface elevation 450 Powerhouse located at tidewater Average annual discharge 237.5 cfs Estimated power capacity - 6400 kW Estimated firm annual energy - 56,400 MW/hrs d. Case 2a Maximum operating reservoir water surface elevation 450 Powerhouse located on Duck River at elevation 65 Average annual discharge 237.5 cfs Estimated power capacity - 5300 kW Estimated firm annual energy - 46,700 MW/hrs 7.3.3 Siting, Conceptual Design and Capital Costs 7.3.3.1 General The hydroelectric development proposed for Silver Lake is based a 120 ft high concrete dam located at the lake mouth. Water would be transported by a 6000 ft penstock 7 to 8 ft in diameter to a powerhouse and would then be returned to the Duck River. The dam would have a concrete gravity non-overflow section, with intake diversion works incorporated into the dam proper. A spillway would be located in the southwest abutment. It has been assumed that’ the foundations at the proposed dam site are suitable for the proposed dam and that there is a suitable aggregate source on-site for required construction materials. The powerhouse would contain two or three horizontal Francis units of 4.0 to 5.0 MW capacity each, depending on final demand requirement. STONE & WEBSTER A -41- Two schemes have been studied, one with 9 and one with 15 MW installed capacity. Conceptual site plan and designs for the 15 MW facility are provided in Figures 7.3-3 through 7.3-5. The powerhouse for each scheme is located at elevation 65 about 3000 ft upstream of the river mouth at low mean tide. This location is advantageous because the water would be returned to the channel upstream of the stretch identified by the Alaska Department of Fish and Wildlife as a major spawning ground. Should powerhouse generation be interrupted a by-pass would divert penstock water into the Duck River. A potential design problem affects the siting of the powerhouse since a major thrust fault crosses the Duck River at the Lagoon. This must be studied in detail before its impact on the proposed development can be assessed. 7.3.4 Maintenance and Operations Silver Lake hydroelectric equipment would consist of a horizontal axis Francis Turbine, governor, generator, transformers, breakers and auxiliary support devices. Standard equipment would be used to allow for easier parts replacement and maintenance. Operations would be remote controlled, but will require daily in-plant inspection of control and equipment settings, daily equipment lubrication, and other minor work tasks. Assumed annual maintenance and operations costs of $120,000 are based on one full time employee living at the project site and all other personnel "on-call" from one of the surrounding communities. This estimate compares favorably with existing hydroelectric installations of similar installed capacity and automation. The proposed plant design provides for continuous availability. Outages would be strictly related to the availability of the transmission line between Silver Lake and Cordova. Diesel generators would be available as a back-up power source in Cordova should power from Silver Lake not be available. 7.3.5 Economic Analysis The capital costs for Silver Lake were developed based on two installed capacities, one of 9 MW and the second of 15 MW. These costs are $39,186,000 and $50,200,000, respectively and include a 30 percent contingency for indeterminants. Operation and maintenance costs are estimated to be $120,000 per year, and diesel generator back-up would have a capital cost of $3,400,000. Present worth life cycle cost for the 9 MW installation is $56,200,000 and for the 15 MW installation is $66,000,000. STONE & WEBSTER A -42- TABLE 7.3-1 POWER CREEK FLOW CORRELATION FOR SILVER LAKE RESERVOIR OPERATION Avg. Depleted Percent of Storage Based Mean Stream Average Annual As a % of Avg. Year Flow Rank Stream Flow Annual FLow 1948 274.0 7 eT + 11 Spill 1949 247.0 16 100 + 0 1950 263.0 12 106 + 6 Spill 1951 231.0 23 94 - 6 1952 245.0 18 99 - 7 1953 300.0 3 121 + 14 Spill 1954 233.0 22 94 - 6 1955 246.0 17 100 - 6 1956 220.0 26 89 - 17 1957 260.0 13 105 ene 1958 321.0 2 130 + 18 Spill 1959 219.0 aT 89 pL 1960 264.0 10 107 - 4 1961 259.0 14 105 + 1 Spill 1962* 205.0 30 83 - 17 1963* 250.0 15 101 - 16 1964* 223.0 25 90 - 26 1965* 236.0 19 96 - 30 1966* 235.0 al 95 - 35 1967* 265.0 8 107 - 28 1968* 228.0 24 92 - 36 1969* 181.0 32 73 - 63 1970* 288.0 5 117 - 46 1971* 236.0 20 96 - 50 197.2* 211.0 28 85 - 65 1973* 195.0 31 719 - 86 1974* 180.0 33 (3 -113 1975 263.0 ie 106 -107 1976 292.0 4 118 - 89 1977 336.0 1 136 - 53 1978 210.0 29 85 - 68 1979 264.0 9 107 - 61 1980 284.0 6 115 - 46 *The storage required at Silver Lake to meet the series of low flow years from 1962 to 1974 would be approximately 160,000 acre-ft. based on an average flow of 200 cfs. > STONE & WEBSTER A 10. 1l. 12. 13. 14. TABLE 7.3-2 COST ESTIMATE SILVER LAKE MOBILIZATION AND SITE PREPARATION WORK LAND AND DAMAGES DAM, INTAKE AND SPILLWAY PENSTOCK POWERPLANT BUILDING, GROUNDS AND UTILITIES TOTAL DIRECT COSTS ENGINEERING AND DESIGN (10%) CONSTRUCTION MANAGEMENT (10%) SUBTOTAL CONTINGENCY (30%) TOTAL PROJECT COSTS INTEREST DURING CONSTRUCTION TOTAL COST Costs ($1000) Installed Capacity 9 MW 1,100.0 =O 5,254.0 13,540.0 3,879.3 250.0 24,014.3 2,401.4 2,401.4 28,817.1 8,645.1 37,462.2 Lese3 39,185.5 15 MW 1,100.0 -0- 5,539.9 18, 080.0 5,799.9 250.0 30,769.8 3,077.0 3,077.0 36,923.8 11,077.1 48,000.9 2,207.9 50, 208.8 STONE & WEBSTER A ecozscos ws 305.9 Wiser NATIONAL NOTE: DASHED CONTOURS ENLARGED FROM CORDOVA D-7 QUADRANGLE FIGURES WITHIN LAKE ARE BOTTOM ELEVATIONS. DAM SITE SILVER LAKE ws 306 PROFILE Figure 7.3-1 SILVER LAKE (HO2) TOPOGRAPHY AND PROFILE A0382052 DISCHARGE IN SECOND-FEET 20-8 18-1285 7 gee 164 £26 6 #16 26 Figure 7.3-2 SILVER LAKE (HO2) 1913 HYDROGRAPH STONE & WEBSTER A WW - WW V4 oO z OO “J 3s a a \ SPILLWAY Figure 7.3-3 SILVER LAKE (HO2) CONCEPTUAL SITE PLAN scozscoa t ire Ista 36-00 ‘STA 40-00 STA 44-060 STA 48.00 PROFILE - PENSTOCK AND POWER TUNNEL SILVER LAKE SCALE : HORIZ -T.- 200° VERT -1°-50° cv (Typ) 4 a TYPICAL PENSTOCK SECTION Pe a ar eee NTS. TRASH RACK & STOP LOG SLOT PLAN-INTAKE NTS. Figure 7.3-4 SILVER LAKE (HO2) DAM AND PENSTOCK gcozstcos aaa pee Figure 7.3-5 SILVER LAKE (HO2) POWERHOUSE 7-4 ALLISON LAKE 7.4.1 Technical Analysis and System Description 7.4.1.1 Location and Description Allison Lake is located about 5 miles southwest of Valdez. It is located in a high glacial valley bordered on three sides by high mountains with a water surface at elevation 1367. The streams which feed the lake originate from glaciers which comprise about 24 percent of the drainage area. The lake is about 1 mile in length with a maximum width of 0.3 miles, and its maximum depth is approximately 250 ft. The drainage basin is approximately 5.7 square miles. The lake discharges into Allison Creek across a glacial moraine falling 1367 ft in about 2.5 miles to tide water at Port Valdez. 7.4.1.2 History and Background In March 1981, the Corps of Engineers issued an Interim Feasibility Report and Final Environmental Impact Statement, entitled: "Electrical Power for Valdez and the Copper River Basin" which included a discussion of Allison Lake. The Corps of Engineers concluded that a dam would not be feasible due to foundation conditions at the lake, anc that a tunnel with a lake tap is required to develop hydroelectric potential at the site. The following descriptions are based on resource information contained in this Interim Report. 7-4.1.3 Hydrology U.S.G.S. recorded stream flow data is available at Solomon Gulch close to Allison Lake. The stream flow gage at Solomon Gulch is located near tidewater about 1/2 mile downstream from Solomon Lake on Solomon Creek. Flow records are available from July to December, 1948 and October 1949 to September 1956. The average annual runoff is 104,300 acre-ft per year and average stream flow is 144 cfs. The estimate of stream flow prepared for Allison Lake is presented in Table 7.4-l. 7.4.1.4 Geology The bedrock at Allison Lake is mapped as part of the Valdez Group, consisting of graywacke, quartzite, arkose, and some thin beds of slate, shale, conglomerate and mica-schist. Secondary quartz has been emplaced along fractures in these rocks, and ranges from a fraction of an inch to several feet thick. STONE & WEBSTER A nia The site area has undergone extensive faulting, folding and shearing. The extensive Contact Fault, a low angle thrust fault dipping northeast, is mapped approximately 5 miles south of Allison Lake. This fault trends N 65 W and extends for many tens of miles to the east and west of the site. Other faults in the site area include the Jack Bay Fault, Galena Bay Thrust and Whalen Bay Thrust. 7.4.1.5 Reservoir Operation The proposed development at Allison Lake involves a lake tap at elevation 1250 which is about 117 ft below the present water surface elevation. Operation of Allison Lake for hydroelectric power would vary the water surface from its present surface elevation of 1367 ft to a minimum elevation of 1267 ft. The average water surface elevation proposed would be at elevation 1335. Usuable storage provided with this configuration is 19,980 acre-ft. 7.4.1.6 Power The installed capacity of the project would be 8000 kW. Based upon the Corps of Engineers reservoir regulation studies, Firm Annual Energy is estimated to be 32,200 MWhrs respectively. 7.4.3 Siting, Conceptual Design and Capital Costs The siting and conceptual design proposed by the Corps of Engineers is generally acceptable. There are a number of potential problems associated with the tunnel orientation, intake chamber and lake tap which will require additional investigation and may affect construction costs and schedules. The Corps of Engineers has prepared a capital cost estimate for Allison Lake of $37,250,000 which has a 20 percent contingency for indeterminants. This estimate is considered low and for the purpose of this study has been increased to $68,700,000. Further geological investigations, including additional test borings would be required in order to accurately assess tunneling conditions and provide confidence in a final cost estimate. 7.4.4 Maintenance and Operation Hydroelectric equipment would consist of a horizontal axis Francis or Pelton turbine, governor, generator, transformers, breakers and auxiliary mechanical, electrical and control devices. High head hydraulic operated intake gates would also be required. The operating equipment would be remote-controlled, but will require daily in-plant inspection of control and equipment settings, equipment lubrication and other minor work tasks. STONE & WEBSTER A -4y- Annual maintenance and operation costs of $120,000 are based on one full time employee with other personnel on an "on-call" basis from Valdez. This estimate has been confirmed by comparison with other hydroelectric installations of similar installed capacity and automation. 7.4.5 Economic Analysis Capital costs were based upon the Interim Feasibility Report prepared by the Corps of Engineers, escalated to present-day prices with a 50 percent contingency allowed for indeterminants. The capital cost was estimated to be $68,700,000, and operations and maintenance cost is estimated at $120,000 per year. This hydroelectric facility would be provided with a diesel generator back-up source of power with a capital cost of $3,400,000. The present worth cost for the 8 MW installation is $82,446,000. STONE & WEBSTER A TABLE 7.4-1 ALLISON CREEK ESTIMATED STREAMFLOW - CFS YEAR oct Nov DEC JAN FEB MAR APR MAY JUN JUL AUG SEP AVG 1948 38. 35. W. 1 5. a 3 59. 152. 176. 93. 83. 56. 1949 52. 23. 1 5. 35 4 4 30. un. 103. 89. 134. aT. 1950 29. 28. 12. 5. 4 ch 2. 34. 124. gu. 86. 85. 42. 1951 15. 7. 35 0. 1. 2. 3. 18. 66. - 117. 86. 194. 45. 1952 25. 25. Ts 5. 4 35 3; 15. 124. 255. 99. ™. 53. 1953 103. 44. 10. 6 4, 4 6. 16. 164, 138. 17. 59. 65. 1954 48. 12. 6. 4, 4, 3. 4, 55. lal. gu. 120. 83. 46. 1955 47. 25. 4, 4. 4, 3. 3° 12. 108. 174. 122. 43. 46. 1956 19. 9. 6. ts 4, 3. 5. 31. 125. in. 149. 72. 50. 1957 ays 27. 13. 5. 3. 3. 3A 44 121. 104, 99. 175. 51. 1958 54. 35. 9%. 8. 4 4 1. 89. 159. 264. 134. wi. 67. 1959 53. 4 ll. 5. 4 3. 4 66. 130. 150. 70. 42. 46. 1960 44. 19. 10. Te 5. 33 4, 19. 130. 163. 108. 51. 54. 1961 29. 13. 23. %. 5. 4, 6. 93. 120. lai. 118. 84. 52. 1962 39. 15. 8. 1: 4 4, 5. mn. 116. 109. m4. 51. 4o. 1963 33. 22. ATs iT 10. 1 ll. 67. liz. 151. 89. 54. 48. 1964 34. 10. 19. 6. 6s 4, 5 13. 137. 157. 100. 47. 45. 1965 35. 22. 15. 5. 4. 4 10. 47. 122, 96. 90. 97. 46. 1966 44 ll. UD 4, 3. 3. 5. 31. 112. 95. 14. 127. 46. 1967 49. 20. 6s 4, 4 5. 9. nu 128. 14. 101. 131. 51. 1968 23. 28. a 5. ll. 9. 6. 80. 116. 103. n. 51. 43. 1969 24. 4. ae 4, 4, 1 10. 62. 129, 84. 55. 33. 36. 1970 6. 23. 26. 8. 10. 8. ave mn. 122. 128. 128. 61. 52. 1971 35. 19. % 5. 4, 3. ch 20. 130. 181. 113. 52. 48. 1972 39. 11. 4, 4, 3. 2. 2. Th 100. am. 103. 95. 43. 1973 46. 12: 8. 4, 35 a5 4, 48. 105. 102. 98. 36. 39. 1974 “20. 9. 6. 4, 3s 3. 5. 46. 106. 68. ne 93. 36. 1975 63. 28. ll. 5. 4, 3. 5. 44 112. 164. 80. 106. 52. 1976 36. 8. 5. 4, 4, as 9. 154. 2uo. 135. 96. 122. 68. 1977 60. 55. 27. 12. 16. 4, 9. 45. 128. 143. 106. gu. 58. STONE & WEBSTER A 10. dks 12. 13. TABLE 7.4-2 COST ESTIMATE ALLISON LAKE MOBILIZATION AND SITE PREPARATION WORK LAND AND DAMAGES INTAKE WORKS AND PENSTOCK POWERPLANT BUILDINGS, GROUNDS AND UTILITIES TOTAL DIRECT COSTS ENGINEERING AND DESIGN CONSTRUCTION MANAGEMENT (10%) SUBTOTAL CONTINGENCY (50%) TOTAL PROJECT COSTS INTEREST DURING CONSTRUCTION TOTAL COST Costs ($1000) Installed Capacity 8 MW 1,340.0 724.0 28, 039.6 4,629.5 250.0 34, 983.1 3,498.3 3,498.3 41,979.7 20,959.3 62,939.0 2,884.0 65, 823.0 STONE & WEBSTER A 7.5 OTHER SITES 7.5.1 Crater Lake Crater Lake is located northeast of Mt. Eyak near Cordova at an elevation of 1525. Typical flows vary between 1 and 14 cfs, and average annual flow is approximately 6 cfs. With storage an average firm generating capacity of 600 kW and an average annual energy of 5000 MWh could be developed. A concrete faced rock fill dam has been proposed at this site. This would provide a reservoir with approximately 1500 acre-ft of storage. The powerhouse would be equipped with two standard 600 kW Pelton turbines with deflectors for penstock surge protection. The capital cost estimated to devlop this site is $11 million. To confirm basin hydrology, the Corps of Engineers plans to establish a stream flow gaging station at Crater Lake. 7.5.2 Humpback Creek Humpback Creek is located northeast of Crater Lake and discharges into Nelson Bay. This location has been studied by the Corp of Engineers and, due to its drainage area and head, may have some potential for development. A run-of-river installation would be proposed, and only seasonal generation would be feasible due to low stream flows during winter months. The site would not be a dependable year-round source of generation. The drainage basin is approximately 1.75 sq mi and average seasonal flows would vary between 1 and 60 cfs. Due to the seasonal nature of the stream flow at this site, further consideration is not recommended. 7.5.3 Rude River The Rude River is located northeast of Cordova at Nelson Bay. The best hydroelectric site is located in the lower reach of the left fork downstream of Rude Lake where the valley narrows and rock abutments are exposed. This site is considered technically feasible but is glacially dammed by the Cordova Glacier, offering a potential flood breakout problem. The sediment loads appear to be large due to the glacial origination of the river. This location is not recommended for further consideration due to the site risks and the high dam required for site development. 7.5.4 Sheep River Lakes Four lakes are located in the northwest escarpment above the Sheep River near Sheep Bay. The lakes are at elevation 2026, 1550, 1022 and 649 and empty into the Sheep River at elevation 20. STONE & WEBSTER A The lake at elevation 1022 has steep side slopes with avalanche paths. One such path is nearly parallel with any potential surface dam or surface intake. Despite the potential avalanche problems, this site appears developable. The two lower lakes appear to be relatively deep and cut out of rock. Lake 1022 has some slide material at its mouth but this appears to be a relatively thin layer. Expected flows between lakes 1022 and 629 would be relatively small during the winter but would increase significantly during the melt and rain season. The head is relatively large, 393 ft from lake 1022 to lake 629; and 610 ft from lake 629 to the Sheep River. The drainage area is estimated at approximately 3.75 sq mi. The proposed development would have a concrete faced rock fill dam at Lake 649 raising the maximum water surface level to elevation 740, which provides approximately 15,000 acre-ft of storage. Additional storage would be obtained by establishing a regulating tap at Lake 1022. Three standard 1000 kW Pelton turbines are proposed at this site, equipped with deflectors for penstock surge protection. The capital cost estimate to develop this site is $33 million, and the proposed development would provide approximately 16,000 MWhs of average annual energy. 7-5-5 Sahlin Lake Sahlin Lake is west of Sahlin Lagoon off Sheep Bay. Sahlin Creek originates at Sahlin Lake and discharges into Sheep Bay. The lake is located at elevation 650, and is craddled by steep side slopes with some avalanche paths. These avalanche paths should not interfere with a storage dam at this location. Potential development would utilize the head drop from elevation 740 to Sahlin Falls at elevation 20. The head could be increased about 100 ft by a dam with storage of about 5000 acre-ft. Assuming storage capacity at the lake could be developed, an average generating capacity of 600 kW with an average annual energy of 5000 MWh could be developed. The proposed development would incorporate a concrete faced rock fill dam, a 5000 ft penstock 18 inches in diameter, and 2 - 600 kW standard Pelton turbines, equipped with deflectors for penstock surge protection. The capital cost estimate to develop this site is $29 million. 7.5.6 Lake 1123 Lake 1123 is located southwest of Sahlin Lake. This lake drains into an unnamed creek which discharges into Sheep Bay. A small pond is located above Lake 1123. The drainage basin is small, slightly less than 0.5 sq mi and the average yearly flow is approximately 6 cfs with storage, an approximate average generating capacity of 350 kW could be developed. This site is not recommended for further consideration due to its small power generating capability. STONE & WEBSTER A 7-5-7 Lakes 1181 and 1750 These lakes are located southwest of Sahlin Lake draining into an unnamed ereek which discharges into Comfort Cove. The drainage basin is approximately 0.6 sq mi, the average annual flow between lakes 1750 and 1181 is 3 cfs and the average annual flow out of Lake 1181 is 7 cfs. Assuming storage at Lake 1181 and a powerhouse located at elevation 300, an average generating capacity of 400 kW could be developed. This site is not recommended for further consideration due to its small capacity. 7.5.8 Lake 650 Lake 650 is located northwest of Sahlin Lake and drains into an unnamed creek which discharges into Port Gravina. The drainage basin is less than 1.0 sq mi, and average annual discharge is estimated to be 10 cfs. This site is not recommended for further consideration due to its small average annual flow. 7.5.10 Lake 1488 Lake 1488 is located north of the Sheep River. The lake feeds into an unnamed creek which discharges into Beartrap Bay. The drainage basin is approximately 2.7 sq mi with glaciers comprising almost 25 percent of the basin. The average flow has been estimated to be 20 to 30 cfs. No flow during the winter and large flows during the melt and rainy seasons are anticipated. With a powerhouse at elevation 100 and a storage dam at the lake, it would be possible to generate approximately 2500 kW with an average annual energy of 22,000 MWh. The proposed development would include a concrete faced rock fill dam at the lake mouth, raising the maximum water surface level to approximately elevation 1550 to provide 9000 acre-ft of storage. A 7000 ft penstock would feed 2 - 2000 kW Pelton turbines, equipped with deflectors for penstock surge protection. The capital cost estimate to develop this site is $33 million. 7.5.11 Lake 1878 Lake 1878 is located northwest of the Gravina River. This lake empties into Fidalgo Creek which discharges into Port Fidalgo. The drainage basin is approximately 2.4 sq mi with glaciers comprising almost 40 percent of the basin. The average flow has been estimated to be between 10 and 20 efs, with no winter flow and large flows during the melt and rainy seasons anticipated. By establishing a powerhouse at elevation 300 and a storage dam at the lake, it would be possible to generate 2500 kW with an average annual energy of 22,000 MWh. The proposed development would incorporate a concrete faced rock fill dam to raise the maximum water surface elevation to 1980 for 8000 acre-ft of storage. An 8000 ft penstock, 24 inches in diameter, would feed 2 - 2000 kW Pelton turbines, equipped with deflectors for penstock surge protection. The capital cost estimate to develop this site is $92 million. STONE & WEBSTER A -48- 7.5.12 Other Sites Considered Dead Creek, Lake 1975 and Fidalgo Creek identified in the Reconnaissance Report were reviewed and due to environmental, or hydrologic hazards identified below are not recommended for further consideration. Dead Creek is a tributary of the Gravina River which supports major fish spawning activity. Any large dam constructed on this river system would cause a major disruption in spawning activity and would be environmentally unacceptable. Lake 1975 has only an average annual energy capability of 5000 MWh but would cost about the same as Lake 1875. This does not make the site cost effective. Fidalgo Creek would be a run-of-river development and would not be a dependable year-round source of generation. STONE & WEBSTER A 8. TRANSMISSION This section outlines the approach and basic criteria used to analyze technical feasibility and prepare cost estimates for the interties associated with Cordova Power Supply Alternatives. The seven transmission intertie alternatives evaluated are: TOl Cordova to Solomon Gulch - Coastal Route TO2 Cordova to Solomon Gulch - with Tap to Silver TO3 Cordova to Solomon Gulch - Copper River Route TO4 Cordova to Bering River Coal Fields transmission Lake TO5 Cordova to Solomon Gulch - Submarine Cable Route TO6 Palmer to Glennallen Route TO7 Cordova to Whittier - Submarine Cable A map showing the routing of alternatives TOl thru T05 is provided at Figure 8.1-1. Route maps for alternatives TO6 and TO7 will be provided in the Final Phase I Report. The prime concern during evaluation of the transmission intertie alternatives was establishing technical feasibility and preparing accurate cost estimates. A preliminary conceptual design for each alternative was prepared to determine if fatal flaws existed, which would preclude further consideration of that alternative. If no fatal flaws were evident, conceptual design was completed and detailed cost estimates were prepared. 8.1 METHODOLOGY, PARAMETERS 8.1.1 Overland Transmission Facilities For an overland transmission line, several factors were considered to establish the technical feasibility and prepare accurate cost estimates. The most significant of these considerations are: Foundation conditions Wind and ice loadings on the line Voltage and contuctor size Structure type Constructability Environment and socioeconomics The approach used to evaluate all overland route alternatives included: A detailed helicopter reconnaissance to observe meteorological, ecological and construction aspects. Collection of all existing meteorologic data available in geotechnical, the areas of the transmission line routes and development of wind and ice loads. A complete meteorologic report will be included as an appendix to the Final Phase I Report. -50- STONE & WEBSTER A Using information collected from field reconnaissance, aerial photo interpretation, and published geologic information, Geologic maps were prepared which grouped the soils into four categories necessary to establish tower foundations type: (1) bedrock, (2) standard driven pile, (3) highly compressible substrate, and (4) permafrost. Types (2) through (4) are driven pile type foundations. In addition, geologic hazards such as avalanches and glacial mass movements were identified. Using existing information, preliminary environmental assessments were prepared to determine the impact the proposed transmission lines would have on wildlife populations, vegetation, and aircraft traffic in the area, as well as aesthetic impacts resulting from construction of these lines. In addition, a land status map was prepared showing federal, state and private land, and additional subcategories of land ownership or control. Based on the meteorological, geotechnical and environmental information developed, conceptual designs were prepared for each overland route alternative. These included studies to determine conductor type and tension, shielding requirements, structure, foundation, nominal right-of-way requirements, damper requirements, and substation requirements. Construction requirements for each conceptual design were established, and if warranted the designs were modified to improve constructability. Two separate detailed cost estimates were prepared for each alternate route - an engineer's estimate and a contractor's estimate. Discussions were held to resolve any major differences between the two estimates, resulting in realistic estimates of capital cost. 8.1.2 Submarine Cable Facilities The study of submarine cable alternatives had just begun at the time of preparation of this summary report. Therefore, the conceptual design and cost estimates for these alternatives entailed only brief discussions with submarine cable suppliers and experts in the field. A cursory review of the design requirements of each alternative was made and preliminary cost estimates were obtained. In-depth conceptual designs and detailed cost estimates for submarine cable alternatives will be prepared and discussed in detail in the Final Phase I Report. 8.1.3 Single Wire Ground Return The report entitled "Final keport: Reconnaissance Study of Energy Requirements and Alternatives for Cordova", which was prepared for the Power Authority in June 1981, recommends the consideration of Single Wire STONE & WEBSTER A SSI Ground Return (SWGR) as a potential transmission line design alternative. Consequently, a review of the SWGR concept was performed as part of this Feasibility Analysis. As a result of this review, it is recommended that SWGR be deleted as an option for the following reasons: The only use of SWGR to date in Alaska has been for small demonstration projects to electrify small rural villages with loads significantly less than those predicted for Cordova. The use of earth as the normal return current path is presently prohibited by the NESC. The State of Alaska has adopted NESC as a design code for transmission line construction. A bill has been introduced in the in Alaska legislature requesting that this requirement of NESC be waived. Until such legislation is acted on, a special waiver must be requested on a case-by-case basis. The power loss for an SWGR system would be approximately twice that for a conventional 3-phase system. From a reliability standpoint, the mountainous terrain to be traversed, the extreme ice loadings expected, and the size of the project, preclude the use of an unproven gravity-stabilized A-frame structure. The Reconnaissance report indicated that the cost of a SWGR system versus a 3-phase system would be a trade-off. In light of the problems with SWGR noted above, and given no apparent capital cost savings, the use of SWGR is not recommended. STONE & WEBSTER A -52- szozseog ead fe aye Ue Re f ua Poo Nee OB SN re She Se Bo “s rw, an a te ‘ Ste Ze Fg veR keen Wee PSR 4 eS oN ee Oi g E 2 * ene b re Son eT a Sage Fi Wir at: st 4 ~ a 4 fe a Ped f éje4 CORDOVA — SOLOMON GULCH Sean ST: <tc WITH TAP TO SILVER LAKE) oe Sy > sip | beO. jee pt Z 4 nS fo el ae = ye ee o> A Ds Sry, F bs g" "> 4 aes Sneeg PLS oS QRCA aay iN PRINCE TOS — CORDOVA — SOLOMON GULCH (SUBMARINE CABLE ROUTE) celts EM © itGT> 9 Figure 8.1-1 TRANSMISSION INTERTIE ROUTES ALTERNATIVES TO1 THROUGH TO5 8.2 CORDOVA TO SOLOMON GULCH - COASTAL ROUTE (TO1) 8.2.1 Technical Analysis amd System Description The Cordova to Solomon Gulch - Coastal Route consists of two 138/12.5 kV substations and an overland transmission line constructed on guyed, steel structures. The transmission route is along a portion of the eastern perimeter of Prince William Sound and crosses to the Lowe River via the approximate routing proposed by the El Paso Alaska Company, in 1974, for a gas pipeline. Approximate length is 67.8 miles. Refer to Figure 8.1l-1. 8.2.2 Environmental and Socioeconomic Issues a. Potential Impacts The major effect on wildlife would result from construction disturbances at a critical time of year. Pregnant mountain goats and deer may abort or birth prematurely if stressed in spring. During the breeding season, disturbance of eagles and other raptors may cause nest abandonment and the subsequent loss of eggs or young. Colonies of seabirds are easily disturbed by the close proximity of humans, and loud noises. Panicked adults may dislodge eggs from nesting cliffs and their departure exposes the eggs to predators. Construction activity in the vicinity of bear denning areas may force bears to utilize less suitable locations, and spring disturbance may cause early emergence at a time when traditional food sources are not available. Injury or death to birds through collisions with transmission lines does occur. Few collisions take place where’ the transmission line is near other tall objects, such as along the base of a hill or where it passes through a forest with trees equal or greater in height than the line, but valley crossings, such as Nelson Bay, may be susceptible to collision. This problem is of special concern since swans and eagles appear to be particularly susceptible to line strikes. b. Endangered Species No endangered species are found regularly along the transmission line route. Non-endangered subspecies of peregrine falcon may nest along the coast. The Aleutian Canada goose may migrate along the Gulf of Alaska, but migratory routes for these birds have not been established. If they do migrate along the transmission line routes, there is a remote chance that a wire strike could occur. STONE & WEBSTER A -53- e. Light Aircraft The Federal Aviation Administration requires that, except when landing or taking off, small aircraft maintain a height of 500 feet above the surface in sparsely inhabited areas, or a height sufficient to allow a safe emergency landing in uninhabited areas. Since the transmission line towers will have an average height of 67 feet, there should be no conflict with small aircraft under normal flight conditions. Under marginal weather conditions, which are not uncommon in the Cordova area, pilots may attempt to fly at or below the height of the transmission line. However, the transmission line would be at or below treetop level, and aircraft should have no trouble avoiding the lines. The transmission line is generally parallel to normal flight lines, and it is not anticipated that the line would be a hazard to light aircraft, even under marginal weather conditions. 8.2.3 Siting, Conceptual Design and Capital Costs a. Siting The route for this alternative is located along a portion of the eastern perimeter of Prince William Sound. Access for construction can be gained by barge through several inlets in the area of the transmission line. Construction of the transmission line would be by conventional methods where possible and by helicopter in areas of limited access. For this estimate it was assumed construction would be by helicopter working from barge mounted construction camps, which would be relocated as required. b. Conceptual Design The transmission line would be designed for a summertime peak load of 12 megawatts. Voltage would be 138 kV nominal. The power factor to be maintained would be 0.9. The voltage drop across the transmission line would be limited to 5 percent. Meteorologic investigations indicate that radial icing on conductors of up to 5-1/2 inches in conjunction with a 50 MPH wind can be anticipated during the expected life cycle of the transmission line. This extremely severe mechanical loading dictates that the conductor must be a 37 #8 Alumoweld type cable. No shield wire would be required as the outage rate due to lightning for unshielded conductors is expected to be less than 1.4 per 100 miles per year. For cost estimating purposes, it is assumed that insulation would be standard 5-1/2 x 10 inch suspension bells. The tangent structure type used for cost estimating is a guyed, tubular steel’ structure as shown in Figure 8.2-1. Angle and deadend structures would be three-pole, guyed, tubular steel shaft structures. All foundations would be driven pile or rock anchor. STONE & WEBSTER A 54. ec. Capital Costs The capital cost for the Cordova to Solomon Gulch - Coastal Route is estimated to be $28.6 million. This includes design, right-of-way clearing, material and construction for the entire facility and a 10 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. 8.2.4 Maintenance and Operation (To be provided in the Final Phase I Report) 8.2.5 Economic Analysis Economic analysis is not yet complete. However, based on a 40 year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is $29 million. STONE & WEBSTER A WV uszlseaM B 3NOLS NOILVYNDISNOD YSMOL LNAONVL 1-2'8 eanbiy 8.3 CORDOVA TO SOLOMON GULCH - WITH TAP TO SILVER LAKE (TO2) 8.3.1 Technical Analysis and System Description The Cordova to Solomon Gulch - with Tap to Silver Lake route consists of three 138/12.5 kV substations and an overland transmission line constructed on guyed steel structures. The transmission route is along a portion of the eastern perimeter of Prince William Sound and crosses to Valdez Arm along Jack Bay, with a tap to Silver Lake. Approximate length is 82.8 miles. Refer to Figure 8.1-l. 8.3.2 Environmental and Socioeconomic Issues Environmental and socioeconomic issues for this route are identical to those presented for alternative TO0l. See Section 8.2.2. 8.3.3 Siting, Conceptual Design and Capital Costs ae Siting The route for this alternative is located along a portion of the eastern perimeter of Prince William Sound. Refer to Figure 8.1-1. Construction of the transmission line would be similar to that described for alternative TOl. See Section 8.2.3a. b. Conceptual Design The transmission line would be designed for a summertime.peak load of 12 megawatts. Voltage would be 138 kV nominal. The power factor to be maintained would be 0.9. The voltage drop across the transmission line would be limited to 5 percent, conduction, insulation and structures would be similar to that used in alternative T0l1. See section 8.2.3a. ec. Capital Costs The capital cost for the Cordova to Solomon Gulch - with Tap to Silver Lake Route is estimated to be $35.2 million. This figure includes design, right-of-way clearing, material and construction for the entire facility in addition to a 10 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. 8.3.4 Maintenance and Operation (To be provided in the Final Phase I Report) STONE & WEBSTER A -56- 8.3.5 Economic Analysis Economic analysis is not yet complete. However, based on a 40O year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is million. 8.4 CORDOVA TO SOLOMON GULCH - COPPER RIVER ROUTE (T03) 8.4.1 Technical Analysis and System Description The Cordova to Solomon Gulch - Copper River Route consists of two 138/12.5 kV substations and an overland transmission line constructed on guyed, steel structures. The transmission route follows the Copper River Highway to the Tasnuna River and then runs up the Tasnuna, over Marshall Pass and down the Lowe River to Valdez. Approximate length is 132.0 miles. Refer to Figure 8.1-1. 8.4.2 Environmental and Socioeconomic Issues a. Potential Impacts Effects from construction and operation of the Copper River Highway would be far greater than those from this transmission line. The area through which this route passes currently has no permanent residents, and other than people floating the Copper River, receives very little recreational use. Most effects would result from the continuous presence of humans due to road access to a previously unpopulated area. b. Endangered Species No endangered species are found regularly along this transmission line route. Nonendangered subspecies of peregrin falcon may nest along the coast. The endangered subspecies of peregrine falcon may migrate through the Copper River canyon, and the Aleutian Canada goose may migrate along the Gulf of Alaska, but migratory routes for these birds have not been established. If they do migrate along the transmission line routes, there is a remote chance that a wire strike could occur. ec. Light Aircraft The Federal Aviation Administration requires that, except when landing or taking off, small aircraft maintain a height of 500 feet above the surface in sparsely inhabited areas or a height STONE & WEBSTER A “57- 8.3.5 Economic Analysis Economic analysis is not yet complete. However, based on a 40 year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is $36 million. 8.4 CORDOVA TO SOLOMON GULCH - COPPER RIVER ROUTE (TO3) 8.4.1 Technical Analysis and System Description The Cordova to Solomon Gulch - Copper River Route consists of two 138/12.5 kV substations and an overland transmission line constructed on guyed, steel structures. The transmission route follows the Copper River Highway to the Tasnuna River and then runs up the Tasnuna, over Marshall Pass and down the Lowe River to Valdez. Approximate length is 132.0 miles. Refer to Figure 8.1-1. 8.4.2 Environmental and Socioeconomic Issues a. Potential Impacts Effects from construction and operation of the Copper River Highway would be far greater than those from this transmission line. The area through which this route passes currently has no permanent residents, and other than people floating the Copper River, receives very little recreational use. Most effects would result from the continuous presence of humans due to road access to a previously unpopulated area. b. Endangered Species No endangered species are found regularly along this transmission line route. Nonendangered subspecies of peregrin falcon may nest along the coast. The endangered subspecies of peregrine falcon may migrate through the Copper River canyon, and the Aleutian Canada goose may migrate along the Gulf of Alaska, but migratory routes for these birds have not been established. If they do migrate along the transmission line routes, there is a remote chance that a wire strike could occur. e. Light Aircraft The Federal Aviation Administration requires that, except when landing or taking off, small aircraft maintain a height of 500 feet above the surface in sparsely inhabited areas or a height STONE & WEBSTER A -58- conditions. The remainder of the line would use a Dove/AW 556.5 KM 26/7 ACSR/AW conductor. No shield wire would be required as the outage rate due to lightning for unshielded conductors is expected to be less than 1.4 per 100 miles per year. For cost estimating purposes, it is assumed that insulation would be standard 5-1/2 x 10 inch suspension bells. The tangent structure type used for cost estimating is a guyed, tubular steel structure as shown in Figure 8.2-1. Angle and deadend structures would be three-pole, guyed, tubular steel shaft structures. A few lattice steel towers would be required at river crossing locations. All foundations would be driven pile or rock anchor. ce. Capital Costs The capital cost for the Cordova to Solomon Gulch - Copper River Route is estimated to be $58.5 million. This figure is inclusive of design, right-of-way clearing, material and construction for the entire facility in addition to a 10 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. 8.4.4 Maintenance and Operation (To be provided in the Final Phase I Report) 8.4.5 Economic Analysis Economic analysis is not yet complete. However, based on a 40 year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is $59 million. 8.5 CORDOVA TO BERING RIVER COAL FIELDS (TO4) The Cordova to Bering River Coal Fields Route consists of two 138/12.5 kV substations and an overland transmission line constructed on guyed, steel structures. The transmission route follows the Copper River Highway to the east side of the Copper River near Sheep Creek where it turns and heads east to Carbon Camp. Approximate length is 61.2 miles. 8.5.2 Environmental and Socioeconomic Issues Environmental and socioeconomic issues associated with the Cordova to Bering River Coal Field Route (TO4) are similar to those noted for alternative TOl. See Section 8.2.2. STONE & WEBSTER a -59- 8.5.3 Siting, Conceptual Design and Capital Cost a. Siting The route for this alternative parallels the Copper River Highway to the east side of the Copper River near Sheep Creek, where it turns and heads east to Carbon Camp. Access for construction can be gained for roughly half of the route from the Copper River Highway. The remainder of the line is generally on flat land that could support track vehicles during winter months when the ground is frozen. Construction could be by helicopter or track vehicle working from two construction camps - one near Cordova and one near Carbon Camp. b. Conceptual Design The transmission line would be designed for a summertime peak load of 12 megawatts. Voltage would be 138 kV nominal. The power factor to be maintained would be 0.9. The voltage drop across the transmission line would be limited to 5 percent. Metearologic investigation indicates that on certain areas of the line radial icing on conductors of up to 5-1/2 inches in conjunction with a 50 MPH wind can be anticipated during the expected life cycle of the transmission line. These areas represent roughly one-fourth the line length and include the portion of line across the Copper River Delta from McKinley Peak to Sheep Creek. This extremely severe mechanical loading dictates that the conductor must be a 37 #8 Alumoweld type cable in the areas exposed to such conditions. The remainder of the line would use a Dove/AW 556.5 KCM 26/7 ACSR/AW conductor. No shield wire would be required as the outage rate due to lightning for unshielded conductors is expected to be less than 1.4 per 100 miles per year. For cost estimating purposes, it is assumed that insulation would be standard 5-1/2 x 10 inch suspension bells. The tangent structure type used for cost estimating is a guyed, tubular steel structure as shown in Figure 8.2-1. Angle and deadend structures would be three-pole, guyed, tubular steel shaft structures. A few lattice steel towers would be required at river crossing locations. All foundations would be driven pile or rock anchor. ec. Capital Costs The capital cost for the Cordova to Bering River Coal Field Route is estimted to be $28.5 million. This figure is inclusive of design, right-of-way clearing, material and construction for the entire facility in addition to a 10 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. STONE & WEBSTER Xd 8.5.4 Maintenance and Operation (To be provided in the Final Phase I Report) 8.5.5 Economic Analysis Economic analysis is not yet complete. However, based on a 40 year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is $25 million. 8.6 CORDOVA TO SOLOMON GULCH - SUBMARINE CABLE ROUTE (TO05) 8.6.1 Technical Analysis and System Description The Cordova to Solomon Gulch - Submarine Cable Route consists of two 138/12.5 kV substations, approximately 10 miles of overhead transmission line constructed on guyed, steel structures, approximately 75 miles of direct circuit submarine cable and two converter substations. Refer to Figure 8.1-1l. 8.6.2 Environmental and Socioeconomic Issues (To be provided in the Final Phase I Report) 8.6.3 Siting, Conceptual Design and Capital Cost a. Siting and Conceptual Design (To be provided in the Final Phase I Report) b. Capital Cost The capital cost for the Cordova to Solomon Gulch - Submarine Cable Route is estimated to be $36.7 million. This figure is inclusive of design, right-of-way clearing, material and construction for the entire facility in addition to a 30 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. 8.6.4 Maintenance and Operation (To be provided in the Final Phase I Report.) STONE & WEBSTER A -61l- 8.6.5 Economic Analysis (To be provided in the Final Phase I Report ) 8.7 PALMER TO GLENNALLEN (T06) 8.7.1 Technical Analysis and System Description The Palmer to Glennallen Route consists of a 230 kV transmission line from the Anchorage area to the Glennallen area with routing parallel to the Glenn Highway, modifications to two existing substations and installation of one new substation. Approximate length is 155 miles. Refer to Figure 8.1-2. 8.7.2 Environmental and Socioeconomic Issues (To be provided in Final Phase I Report) 8.7.3 Siting, Conceptual Design and Capital Cost a. Siting and Conceptual Design (To be provided in Final Phase I Report) b. Capital Costs The capital cost for the Palmer to Glennallen Route is estimated to be $68.9 million. This figure is inclusive of design, right-of-way clearing, material and construction for the entire facility in addition to a 30 percent allowance for indeterminants. The cost of right-of-way procurement is not included in the capital cost figure. 8.7.4 Maintenance and Operation (To be provided in the Final Phase I Report) 8.7.5 Economic Analysis Economic analysis is not yet complete. However, based on a 4O year transmission line life, and an estimated annual maintenance cost of $200 per mile, the present life cycle cost for this alternative is $69 million. STONE & WEBSTER A -62- 8.8 CORDOVA TO WHITTIER - SUBMARINE CABLE (107) The Cordova to Whittier - Submarine Cable alternative consists of approximately 110 miles of submarine cable from Cordova to Whittier across Prince William Sound. Due to sea depths in excess of 1200 feet, cable design for this alternative would be state-of-the-art. Costs for material only would be in excess of $150 per foot and $87 million for the entire project. No further investigation is recommended. STONE & WEBSTER A ~63 9. ECONOMICS (To be provided in the Final Phase I Report) STONE & WEBSTER A -64- 10. COMPARISON OF ALTERNATIVES (To be provided in the Final Phase I Report) STONE & WEBSTER A -65- 11. RECOMMENDATIONS 11.1 SELECTED ALTERNATIVE(S) Investigation of alternatives and development of energy supply plans for Cordova are far from complete. However, based on results of analyses completed through March 10, 1982, several recommendations can now be made. 11.1.1 Diesel and Coal-Fired Generation It is now apparent that diesel and coal-fired generation alternatives are not competitive with hydroelectric power. Therefore, only the existing diesel plant (D01) should be developed further to provide a base case comparison for other more competetive alternatives. 11.1.2 Hydroelectric Generation In the case of hydroelectric alternatives, development of Power Creek is considered an unacceptable technical risk, and capital costs for Allison Lake are excessive when compared with Silver Lake. It is therefore recommended that further hydroelectric investigations be limited to Silver Lake as a primary condidate for power supply, and Crater Lake and other small hydroelectric sites as supplemental power sources. 11.1.3 Transmission Interties Analysis of transmission line costs indicates that the Copper River Route from Cordova to Solomon Gulch and the Cordova to Whittier Submarine Cable are not cost competitive with other equivalent routes and further investigation of these alternatives is not warranted. 11.1.4 Recommended Alternatives It is recommended that continued investigation be limited to the following seven alternatives. DOl DIESEL BASE CASE HO2 SILVER LAKE HYDROELECTRIC HO5 HYDROELECTRIC SITES WITH LESS THAN 3 MW CAPACITY TOl CORDOVA TO SOLOMON GULCH INTERTIE - COASTAL ROUTE TO2 CORDOVA TO SOLOMON GULCH INTERTIE - WITH TAP TO SILVER LAKE TO5 CORDOVA TO SOLOMON GULCH INTERTIE - SUBMARINE CABLE TO06 TEELAND-PALMER-GLENNALLEN INTERTIE STONE & WEBSTER A -66- 11.5.1 Other Recommendations At this stage of investigation, the Silver Lake hydroelectric option appears to be very competitive. However, were it to be selected as the preferred plan for Cordova, further development and optimization would be hampered by a lack of field data. Therefore, it would be cost effective to begin stream flow data collection prior to completion of Phase I. This would save perhaps as much as one year in total time required if Silver Lake is finally selected as part of the preferred power supply plan for Cordova. 11.2 PHASE II ACTIVITIES (To be provided in the Final Phase I Report) STONE & WEBSTER A -67-